This comment letter response contains two parts:   

(1) The original submittal from the commenter.

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

Notes about the response letters:

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

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

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

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

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

individual response. These are described and explained below.  

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

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

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

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

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

appropriately addressed.

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

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

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

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

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

construction requirements).  

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

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

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

commenter was given a unique response.

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

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

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

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

and attention to each comment letter that was submitted.   

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

Responses on each topic area are compiled and are also available in the rulemaking docket.
Docket ID No. EPA–HQ–OW–2008–0390 

 December 23, 2008 

Comments of the Carbon Sequestration Council

on Proposed UIC Program for 

Carbon Dioxide Geologic Sequestration

The Carbon Sequestration Council (CSC) is pleased to submit these comments and 

recommendations to the Environmental Protection Agency (EPA) in response to the proposed rule 

for geologic sequestration of carbon dioxide under the Safe Drinking Water Act (SDWA) "Federal 

Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) 

Geologic Sequestration (GS) Wells," 73 Fed. Reg. 43491-541 (July 25, 2008), Docket ID No. EPA–

HQ–OW–2008–0390. CSC was formed to provide a forum for inter-industry communication 

around key issues of carbon capture and sequestration (CCS) including policy, funding, and 

messaging. CSC facilitates information sharing and consensus building to more effectively promote 

policies, legislation and regulatory frameworks that foster the use of anthropogenic CO2 for 

enhanced oil recovery (EOR) as well as the early use and commercial deployment of CCS as a means 

of addressing greenhouse gas mitigation. Current CSC membership includes Ameren, American 

Electric Power Service Corporation, Anadarko Petroleum Corporation, BHP Billiton, BP 

Alternative Energy, ConocoPhillips, Duke Energy, E.ON US, NRG Energy, Occidental Petroleum 

Corporation, Shell Oil Company, Southern Company, and Xcel Energy. CSC has developed and 

participated in coordinated, multi-stakeholder approaches for providing input to a number of 

ongoing processes, including the EPA’s technical and rule development workshops, the 

development of CCS Guidelines by the World Resources Institute, the development of 

recommendations by the Ground Water Protection Council, and the development of regulatory 

frameworks by a number of states. CSC has also convened and shared ideas with a broad range of 

interested stakeholders. 

CSC has participated in the development of the multi-stakeholder discussion (MSD) process leading 

to the submission of a joint letter to EPA. We join the other participants in expressing our 

appreciation for EPA’s extension of the public comment period that allowed us to make substantial 

progress in expanding our shared understanding on the relevant issues and to reach significant 

agreement on how these issues can be addressed and resolved by EPA. CSC supports all of the 

recommendations presented in that letter, which are submitted with the request that the 

recommendations be considered as a whole because the recommendations were developed in 

combination to accurately reflect our shared understanding. 

In addition, we are committed to continuing the MSD process and to inviting others to participate 

with an objective of developing additional specific recommendations for improvement of a final rule 

that could be adopted by EPA’s scheduled date in late 2010 or early 2011, including development of 

the requirements to be applied to oil and gas reservoir geologic sequestration that is not conducted 

in conjunction with enhanced oil and gas production operations. We will be working with the other 

MSD participants toward submission of additional recommendations by February 28, 2009.

The comments of the CSC are submitted in four parts, including (1) these general comments, (2) the 

specific recommendations for revision of the proposed regulations presented in Attachment A, (3) 

responses to a number of specific requests for comment presented by EPA in the preamble to the 

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Docket ID No. EPA–HQ–OW–2008–0390 

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proposed rule, which are presented in Attachment B, and (4) the joint MSD letter, which is being 

submitted separately for consideration by EPA and for inclusion in the docket for EPA’s proposal. 

I. Introduction

We strongly support EPA’s effort to develop appropriate regulations governing CO2 injection for 

purposes of GS. We agree that GS is an important option for the reduction of CO2 emissions, that 

the UIC program provides the appropriate framework for the regulation of CO2 injection, and that 

UIC regulations specifically tailored to CO2 injection could play a vital role in facilitating the 

development and implementation of GS projects while ensuring that appropriate environmental 

safeguards are in place. 

As EPA has correctly recognized, it is critical that any UIC program regulation addressing GS be 

designed to achieve two goals. First – obviously – such a rule should ensure that CO2 injection is 

conducted in a manner that is protective of human health and the environment. Second, such a rule 

should effectively facilitate the development of GS as a means for greenhouse gas (GHG) 

mitigation. EPA’s rulemaking effort will prove successful only to the extent that both of these goals 

are achieved. 

Fortunately, there is abundant evidence that CO2 injection can be accomplished in a manner that is 

protective of human health and the environment. Indeed there has been a long history of successful 

injection well operation in the United States, and multiple studies have confirmed that the UIC 

program has been remarkably effective in ensuring protection of human health and the 

environment. While GS projects are likely to be large in scale, it is important to recognize that the 

injection of CO2 is nothing new. To the contrary, CO2 has been injected for purposes of enhanced 

oil and gas recovery (EOR/EGR) for more than thirty-five years, and the UIC program already 

regulates more than thirteen thousand CO2 injection wells that have successfully injected more than 

600 million tons of CO2. Accordingly, there is a vast body of experience demonstrating that CO2 

injection can be conducted without adverse impacts on human health and the environment. 

Unfortunately, the proposed rule does not seem to reflect an adequate appreciation of the 

demonstrated strength and experience of the UIC program. Instead the proposal appears to be 

based on an exaggerated assessment of the risks and challenges involved in CO2 injection; as a result 

the proposed rule would impose requirements that are substantially more elaborate, burdensome 

and prescriptive than necessary to protect human health and the environment. Because such 

requirements would impose regulatory burdens that are disproportionate to any environmental 

benefits they might provide, they would do more to impede and deter GS than to facilitate its 

responsible use. 

To achieve its goals for this rulemaking – to address the risks of CO2 injection and promote the 

development of GS – EPA must take a hard look at the need for, and practical utility of, each of the 

requirements it has proposed for CO2 injection. As further detailed in these Comments, we believe 

that the proposed requirements can and should be streamlined significantly to increase the flexibility 

of the requirements for CO2 injection and reduce the unnecessary (and ultimately 

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counterproductive) regulatory burdens the proposed rule would impose. We respectfully urge EPA 

to modify its proposed regulatory approach accordingly. 

II. General Comments

A. We Support Development of Appropriate UIC Program Regulations for GS. 

We support EPA’s conclusion that the UIC program provides an appropriate framework for 

regulation of carbon dioxide (CO2) injection for geologic sequestration (GS). The UIC program 

governs a very wide range of underground injection activities – including the operation of thousands 

of existing CO2 injection wells – and enjoys an extensively documented record of success. The 

program has in many respects been a model for Federal-State cooperation, and has benefited from a 

long history of regulatory and technical discourse among agencies and regulators armed with 

considerable practical experience and exceptional technical expertise. While the UIC program is 

focused on the protection of “underground sources of drinking water” (USDWs), this seemingly 

narrow objective is narrow in name only. In fact, the measures the UIC program relies upon to 

protect USDWs – measures designed to ensure that injected material remains isolated in the deep 

subsurface – are by nature sufficient to ensure protection of human health and the environment. 

The UIC program currently provides regulations that can be (and are being) successfully applied to 

CO2 injection into oil and gas reservoirs. We also agree that it makes sense to develop regulations 

more specifically designed to address CO2 injection in the GS context especially for formations that 

are not oil and gas reservoirs. Such regulations can and should be designed to build on relevant UIC 

program experience, including experience with CO2 injection, and should be tailored to address the 

particular needs for this category of injection activity: both the need to protect USDWs and the need 

to facilitate use of GS as a technology for reducing CO2 emissions. Those regulations should follow 

a flexible, performance-based approach that allows regulators to tailor specific permit requirements 

as appropriate based on the broad range of injection sites and practices that may be encountered in 

the GS context and on the body of knowledge and experience that will be gained not only from pilot 

and demonstration projects, but from the initial deployment of commercial scale geologic 

sequestration projects. 

Moreover, the safeguards of the UIC program have been adequate to protect USDWs of all types, 

including sole source aquifers, from injection that occurs substantially below those aquifers even 

where that involves drilling through the aquifer to construct wells that will inject into deeper 

formations. These drilling activities have not resulted in any significant contamination of sole 

source aquifers and, indeed, have probably served to protect those aquifers by avoiding surface 

disposal operations that would have been more likely to pose threats of endangerment to drinking 

water resources.1/

 

 

1/ Each year, industrial facilities and municipal wastewater treatment plants generate billions of gallons of 

hazardous and non-hazardous waste. Class I injection wells provide a safe means to remove these wastes from the 

surface environment by isolating them deep below the land surface, away from drinking water resources. 

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B. We Support Continued Application of the Class II Regulations to CO2 

Injection in the Enhanced Oil or Gas Recovery Context and for GS in Oil and 

Gas Reservoirs and the Creation of “Class VI” Regulations to Address Most 

Other CO2 Injection Wells Used for GS. 

CO2 injection wells are currently permitted as Class II or Class V “experimental technology” wells. 

Under the proposed rule, Class II CO2 injection in conjunction with oil and gas production would 

remain under Class II, and a new classification – Class VI – would be created for GS. This 

approach makes sense except that all injection of CO2 in oil and gas reservoirs, including injection 

for GS, should remain in Class II to avoid circumstances where EOR operations might be 

compelled to shift back and forth between Class II and Class VI depending on market conditions. 

CO2 injection for purposes of enhanced oil or gas recovery (“EOR/EGR”) has been successfully 

regulated as Class II injection for decades, and we agree with EPA that there is nothing to justify any 

disruption of the existing regulatory regime for the thousands of injection wells already in use in 

these operations. For other GS injection projects outside of oil and gas reservoirs, Class VI 

regulations would permit a more structured basis for regulation than the current Class V regulations. 

As EPA has recognized, the creation of a new well class does raise some applicability and transition 

issues. The key applicability issue relates to the distinction between Class II and Class VI when CO2

is injected for the purpose of GS in connection with EOR/EGR operations. EPA’s Proposal would 

continue to regulate and permit injection of CO2 for EOR/EGR purposes as Class II injection “as 

long as any production is occurring.” EPA has asked for comment on the merits of this approach 

“since owners or operators of some Class II EOR/EGR wells may wish to use wells for the 

purposes of production and GS prior to the field being completely depleted.” 73 Fed. Reg. at 

43502. In fact, it is more than likely that CO2 will be injected both for purposes of EOR/EGR and

GS. The rules should be clarified to be consistent with EPA’s intent, as we understand it, that where 

GS of CO2 occurs in connection with EOR/EGR activities the applicable class of wells and 

regulatory requirements is Class II. Furthermore, the UIC rules should provide a “bright line” 

standard for determining when EOR/EGR production activities cease and CO2 injection for GS 

continues. When EOR/EGR production activities cease and CO2 injection for purpose of GS 

continues, the risk profile changes, as further discussed below. This potential change in risk profile 

would necessitate additional requirements that are commensurate with both the historic EOR/EGR 

operations in the particular oil and gas field and with the risk profile of continued CO2 injection for 

 

 Class I injection wells inject far below the lowermost USDW. Injection zones typically range from 1,700 to 

more than 10,000 feet in depth. The injection zone is separated from USDWs by an impermeable “cap” rock called the 

confining layer, along with additional layers of permeable and impermeable rock and sediment that separate the injection 

layer from the USDW. 

http://www.epa.gov/safewater/uic/wells_class1.html 

 

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GS. The MSD joint letter states that the Group has agreed that the wells used for GS in oil and gas 

reservoirs that do not meet the criteria of (b)(4) should be subject to additional requirements” and 

indicates further that the Group has “tentatively defined such wells as wells used ‘for geologic 

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

There may be a further recommendation that EPA establish a Class II regulatory regime for 

continued injection of CO2 for GS when EOR/EGR production has been terminated based upon a 

“bright line” definition. These topics are discussed in further detail below. 

In the course of a typical EOR operation, even where there is no intent to sequester, 30-50% of the 

injected CO2 will remain in the reservoir after production operations cease. The balance is either 

dissolved within the produced oil or recycled for use in other reservoirs; it is not emitted to the 

atmosphere. Today approximately 90% of the CO2 used in enhanced recovery operations is 

produced from naturally occurring geologic accumulations. Rather than using this naturally 

occurring CO2, operators should be encouraged to mitigate greenhouse gas emissions by using 

anthropogenic CO2 instead. Oil and gas reservoirs have proved capable of containing water-buoyant 

fluids and gases for millions of years. These reservoirs are well studied and they offer the best 

opportunity to kick-start large-scale geologic storage of CO2 building on 100 years of oil field 

operating experience. Accordingly, EOR/EGR operations using the same procedures now in place 

would result in sequestering anthropogenic CO2 and should continue to be subject to the same 

requirements that have successfully protected USDWs since the inception of enhanced recovery 

operations. EPA should therefore clarify that EOR/EGR operations that include CO2 injection for 

the purpose of sequestration, or what is sometimes called “EOR with sequestration,” will remain 

covered by Class II requirements. EPA recognition of EOR with anthropogenic CO2 as a valid 

form of geologic sequestration will provide much needed incentive for near-term geologic 

sequestration efforts, while longer-term cap and trade or taxation schemes develop. As long as oil 

or gas production continues, this remains an EOR/EGR operation and should remain in Class II. 

There are two different transition issues; the first of which involves the status of Class II CO2 

injection wells after oil and gas recovery operations cease. In this situation, EPA should revise its 

proposal to retain the regulation of all GS in oil and gas reservoirs in Class II, subject to appropriate 

requirements as discussed below. Rather than require such wells to be permitted as Class VI wells – 

often by regulators in a different state agency than that authorized to administer the Class II 

program – this approach would leave permitting in the hands of the regulators with existing 

knowledge and expertise with respect to the oil and gas reservoirs and injection wells involved, thus 

leveraging regulatory resources and facilitating the seamless transition of oil and gas reservoirs to GS 

service following the completion of EOR/EGR operations. This approach would also reduce 

administrative complications or jurisdictional complexities that might otherwise arise and would 

provide additional regulatory flexibility in situations where production may stop and start in 

response to changing market conditions. 

The other transition issue involves the substantive requirements that should apply to existing, 

currently-permitted wells that are converted to GS service. The preamble indicates that “the owner 

or operator would need to follow the permitting process outlined in today’s proposal to receive a 

Class VI permit,” but EPA proposes “to give the Director discretion to carry over or ‘grandfather’ 

the construction requirements for existing wells if the Director makes a determination “that these 

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wells would not endanger USDWs.” 73 Fed. Reg. at 43502. This approach seems backwards: 

having recognized the problems associated with the application of new well construction standards 

to existing wells, EPA should recognize that the well construction standards for all well classes are 

designed to ensure that USDWs are not endangered. Consequently, in the absence of some specific 

evidence of a construction problem that might endanger a USDW, there is no basis to question the 

construction of an existing, previously-permitted injection well, and any “grandfathering” with 

respect to the Class VI construction requirements should be virtually automatic. 

In addition, it is important to recognize that the need and justification for “grandfathering” is not 

limited to construction requirements. There are also proposed Class VI operational and monitoring 

requirements that would require the substantial modification – if not outright abandonment – of 

many existing CO2 injection wells (the proposed requirement for continuous monitoring of annulus 

pressure is a conspicuous example). In every case, the wells at issue have already been constructed 

consistent with requirements that UIC program officials have determined to be sufficient to prevent 

endangerment of USDWs. In view of this fact, there should be a regulatory presumption – absent 

some specific information to the contrary – that continued operation of wells already in CO2 service 

for CO2 injection will also be protective of USDWs. 

The proposed Class VI regulations would require a relatively elaborate demonstration that injected 

CO2 will remain isolated from USDWs, and some supplementation of the permit requirements for 

existing wells may be appropriate consistent with the broad geological containment standards for 

Class VI wells. To the extent these or other supplemental requirements are truly necessary, they 

could and should be imposed through modification or supplementation of existing permit 

conditions rather than through the wholesale application of Class VI program requirements to preexisting activities already found to be protective of USDWs. Accordingly, we recommend that the 

Final Rule include a presumption that wells already in CO2 service be allowed to transition to Class 

VI status—or, in the case of Class II wells, to remain in Class II and be used for GS—based on their 

existing permit conditions, subject only to additional requirements as necessary to demonstrate 

geologic containment of the injected CO2 stream. 

C. Class VI Injection Should Not be Limited to Injection Below the Lowermost 

USDW. 

The proposed rule limits Class VI injection to injection into formations that are below the 

lowermost underground source of drinking water (USDW). This requirement is not necessary for 

the protection of USDWs and would remove a substantial number of viable formations from 

consideration for GS. There are examples of existing CO2 injection wells (in the EOR/EGR 

context) that demonstrate that it is possible to inject CO2 above the lowermost USDW without 

causing any endangerment of USDWs. An excellent example is the Salt Creek EOR project in 

Wyoming, which has a USDW below the injection zone. The Wyoming State Geological Survey has 

already submitted comments emphasizing that restricting injection of CO2 only below the lowermost 

[SDW aquifer “will make it impossible to inject CO2 into deep saline aquifers in Rock Mountain 

Laramide [LARAMIE?] Basins (RMLB).” These comments go on to say: “For economic and 

regulatory purposes, the regulations as proposed will make geological sequestration of CO2

impossible. To promulgate a geological CO2 sequestration regulation for RMLB out of the context 

of Rocky Mountain Laramide [?] geology will make it extremely difficult to mitigate the effects of 

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greenhouse emissions on climate change in the West.” Comments of Ronald Surdam, 

Director/State Geologist, Wyoming State Geological Survey (December 2008). 

D. RCRA/CERCLA Applicability 

In light of the current uses and potential future uses of CO2 for EOR/EGR, EPA has taken a 

sensible approach by proposing to create a new Class VI well category based on the injection of the 

CO2 stream as fluid without characterizing that stream as a waste. It is neither necessary nor helpful 

to categorize CO2 as a pollutant or waste, and that would likely prove detrimental to technology 

development. Indeed, we are concerned that EPA’s brief discussion of a supposed potential for 

injected CO2 streams to be characterized as hazardous waste (or some type of hazardous release) are 

causing apprehension and could have a significant chilling effect on any future deployment of 

carbon capture and sequestration technologies. Through the work of our engineers and scientists 

with capture technologies and their extensive experience with the types of power plant flue gas likely 

to be sources of CO2 for sequestration, we do not believe that captured CO2 streams should trigger 

the application of either RCRA or CERCLA. Accordingly, we encourage EPA to dispel concerns 

that geologic sequestration could be encumbered with those requirements except possibly through 

the commingling of a captured CO2 stream with an actual waste stream, and we are not suggesting 

that such commingling should be permissible in the GS context. 

1. RCRA Applicability 

EPA’s Proposal suggests that injected CO2 may be considered hazardous waste for RCRA 

purposes, and defines “carbon dioxide stream” to exclude hazardous waste. 73 Fed. Reg. at 43503. 

The premise appears to be that CO2 is solid waste, and that a waste determination for such solid 

waste would turn on the specific composition of the CO2 in question. Id. Based on this premise, 

the preamble suggests that “EPA cannot make a categorical determination as to whether injected 

CO2 is hazardous waste under RCRA.” Id. 

In fact, there are important categorical determinations that EPA can and should make with respect 

to the RCRA status of CO2. We urge EPA to make these determinations as follows. 

First, EPA should clarify that gas-phase CO2 is not solid or hazardous waste for RCRA purposes 

and is not subject to any RCRA waste determination requirements. 

The RCRA definition of “solid waste” does not include gaseous material unless it is “contained.” 

RCRA 1004(27), 42 U.S.C. 6903(27). EPA has long taken the position that gasses do not qualify as 

“solid waste” under this definition unless they are “contained” in a cylinder or similar container. 54 

Fed. Reg. 50968 at 50970, 50973 (December 11, 1989). It follows that gas-phase CO2 streams are 

not solid waste, are not subject to the waste determination requirements of 40 C.F.R. 262.11, and 

cannot be considered hazardous waste for RCRA purposes. 

Second, EPA should clarify that supercritical CO2 is not solid or hazardous waste for RCRA 

purposes and is not subject to any RCRA waste determination requirements. 

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Again, the RCRA definition of solid waste is limited to “solid, liquid, semi-solid, or contained 

gaseous material.” RCRA 1004(27). Because supercritical CO2 is none of these things; a plain 

reading of the statutory text suggests that supercritical CO2 should not be considered “solid waste.” 

This reading of the statute makes sense, because RCRA is plainly aimed at the kind of material that 

could end up being dumped into a landfill. Uncontained supercritical CO2 is not such a material. 

Instead, the physical properties of supercritical CO2 are such that it would immediately vaporize – 

becoming an uncontained gas – before it could contribute to the contents of a landfill. A related 

practical consideration is the fact that the hazardous characteristics – the broad waste determination 

criteria that provide a primary means for determining when solid waste is hazardous waste – are 

based largely on test methods that are inapplicable to materials such as supercritical CO2. In 

particular, the toxicity characteristic depends on test methods that can only be applied to materials 

that are solids or liquids at standard temperatures and pressures. This is unsurprising, because the 

toxicity characteristic was designed to assess the threat waste would have in a municipal landfill 

disposal scenario, a scenario that – as already discussed – is inherently inapplicable to uncontained 

supercritical CO2. Accordingly, it makes no legal, policy, or practical sense to treat uncontained 

supercritical CO2 as “solid waste” for RCRA purposes. EPA should therefore confirm that 

uncontained supercritical CO2 is not “solid waste” and is not subject to RCRA waste determination 

requirements. 

It follows that a CO2 stream would only qualify as “solid waste” if it is actually in the form of a 

liquid (i.e., a liquid containing dissolved CO2). In such a case, the liquid would meet the statutory 

definition of “solid waste,” the requirement to perform a RCRA waste determination would be 

triggered, and the familiar test methods for waste determinations could be applied.

2. CERCLA Applicability 

The proposed rule raises the specter of CERCLA liability arising out of CO2 geologic sequestration 

(GS) projects. Specifically, in Section II.D. of the preamble, EPA notes several “potential USDW 

impacts,” including the potential that the injected CO2 could (1) force native brines into USDWs; 

(2) contain impurities; or (3) cause naturally occurring or otherwise pre-existing chemicals to be 

mobilized within the injection zone, for example, via the formation of carbonic acid and its leaching 

effects. 73 Fed. Reg. 43492, 43497 (July 25, 2008). EPA then goes so far as to suggest that “The 

migration of formation fluids containing mobilized contaminants could cause endangerment of 

USDWs.” Id. 

EPA reiterates some of these concerns under preamble Section 2.J., under the heading “Is injected 

CO2 considered a hazardous substance under CERCLA?” 73 Fed. Reg. at 43503-04. EPA indicates 

that CO2, while not itself a CERCLA “hazardous substance,” could contain hazardous substance 

impurities. EPA indicates further that “the CO2 stream could react with groundwater to produce 

listed hazardous substances such as sulfuric acid.” 73 Fed. Reg. at 43504. (It is unclear whether the 

reference to groundwater means injection zone formation fluids or USDW formation fluids.) In 

short, the CERCLA liability concerns flagged by EPA arise out of two basic scenarios: (1) preexisting hazardous substances, or hazardous substance impurities or reaction products moving into or 

within the injection zone; and (2) these hazardous substances (or displaced brines) migrating from the 

injection zone. 

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 EPA also states: 

CERCLA exempts from liability certain “federally permitted releases” including 

releases in compliance with a UIC permit under SDWA. Therefore, Class VI 

requirements and permits will need to be carefully structured to ensure that they do 

not “authorize” inappropriate hazardous releases. This would include clarifying if 

there are potential releases from the well which are outside the scope of the Class VI 

permit. 

73 Fed. Reg. at 43504. 

The first concern raised by EPA does not appear to pose a very serious concern because injection 

into a permitted injection does not constitute a release under CERCLA. EPA has issued some 

relevant guidance in the UIC context. Specifically, EPA has concluded that the emplacement of 

fluids into an injection zone through an authorized injection well does not constitute a “release” for 

purposes of RCRA or CERCLA. See 50 Fed. Reg. 28712 (July 15, 1985). EPA relied upon 

CERCLA’s definition of “release,” which requires hazardous substances to make it into the 

“environment.” Under EPA’s interpretation, UIC injection zones do not constitute the 

“environment,” but rather the injection zone is essentially part of the injection well system. Id. at 

28713. One of the key elements for CERCLA liability is a release (or threatened release) of 

hazardous substances. Therefore, at least with respect to hazardous substances remaining in the 

injection zone, one of the key elements for CERCLA liability would not be met, regardless of 

whether the hazardous substances were in the discharge stream, mobilized pre-existing substances, 

or in-situ reaction products. For clarification, EPA should reiterate this interpretation in the 

preamble to the final GS rule. 

Notwithstanding this interpretation, significant CERCLA liability concerns could remain with 

respect to any migration from the injection zone. While we are unaware of any attempt to date by 

EPA or another government agency or private party, to apply CERCLA to a UIC site in such a 

scenario, or any similar context, the mere possibility is a significant concern that should be addressed 

by EPA in order to avoid serious discouragement of development and investment in CO2 GS 

projects. EPA should clarify in the final regulations the so-called “federally permitted release” 

exemption from CERCLA liability for purposes of the UIC program, as referenced by EPA in the 

preamble to the GS proposal. 73 Fed. Reg. at 43504. The FPR exemption affects two separate 

CERCLA areas: (1) release reporting and (2) cleanup liability. The FPR exemption operates 

differently in each area, and is more accurately characterized as two separate exemptions. 

Under CERCLA’s release reporting provisions, certain releases of hazardous substances are subject 

to a one-time notification requirement, but FPRs are exempt: 

Any person in charge of a vessel or an offshore or an onshore facility shall, as soon as he has 

knowledge of any release (other than a federally permitted release) of a hazardous substance from 

such vessel or facility in quantities equal to or greater than those determined pursuant to 

CERCLA - Sec. 9602 of this title, immediately notify the National Response Center.... 

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42 USC § 9603(a). FPR is in turn defined to include various types of releases/discharges authorized 

under any of several federal or delegated state regulatory programs including “(G) any injection of fluids 

authorized under Federal underground injection control programs or State programs submitted for Federal 

approval (and not disapproved by the Administrator of the Environmental Protection Agency) 

pursuant to part C of the Safe Drinking Water Act [42 U.S.C. 300h et seq.] ...” 42 USC § 9601(10) 

(emphasis added). To apply the FPR exemption in the release reporting context, the issue for UIC 

permittees would simply be whether the release at issue was an authorized injection of fluids. If so, 

the release would not have to be reported. The FPR for cleanup liability purposes is more 

complicated. 

 CERCLA § 107(j) states: 

Recovery by any person (including the United States or any State or Indian tribe) for 

response costs or damages resulting from a federally permitted release shall be pursuant to 

existing law in lieu of this section. Nothing in this paragraph shall affect or modify 

in any way the obligations or liability of any person under any other provision of 

State or Federal law, including common law, for damages, injury, or loss resulting 

from a release of any hazardous substance or for removal or remedial action or the 

costs of removal or remedial action of such hazardous substance.... 

42 USC § 9607(j). First, it is important to understand that the FPR exemption from cleanup liability 

only forecloses a CERCLA action; otherwise-viable actions under other laws remain viable, and are 

not affected. An aggrieved party would be free to assert claims based on any number of other 

causes of action typically utilized in hazardous substance contamination cases, such as common law 

claims for trespass, nuisance, negligence, strict liability, or “toxic tort,” or statutory claims arising 

under state groundwater protection or cleanup liability laws. 

More importantly, in comparison with the release reporting context, the FPR exemption from 

cleanup liability applies not to the FPR directly, but rather to “response costs or damages resulting 

from” the FPR. This parallels CERCLA’s liability imposing provisions, which require a release of 

hazardous substances from a facility “which causes the incurrence of response costs.” This 

exemption is obviously broader than just the FPR itself in that any resulting costs are covered. In 

other words, the measure of the scope of the exemption for liability purposes is not limited to 

whether the release qualifies as a FPR, but rather whether the costs at issue result from the FPR. 

With respect to UIC wells, if the emplacement of fluids through a well is authorized by the permit, 

the resulting costs due to the various circumstances identified by EPA – in-situ reaction or 

mobilization, migration, etc. – remain ultimately the result of the FPR, and would be covered by the 

liability exemption. In other words, but for the authorized injection, the costs would not have been 

incurred. Therefore, the FPR exemption should apply to the scenarios identified by EPA in the 

preamble, with the exception of costs incurred due solely to unauthorized releases – i.e., releases 

resulting from unauthorized injection. 

The scope of the FPR exemption in the CERCLA cleanup liability context has been interpreted 

narrowly by some courts, but none of the cases involved UIC sites. In promulgating the final rule, 

EPA could provide a more reasoned analysis of the FPR exemption, and dispel any unwarranted 

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concerns about CERCLA liability. EPA realized over 20 years ago that CERCLA’s FPR exemption 

needed additional clarification with respect to both release reporting and liability issues. EPA issued 

proposed rules in 1983 and 1988 that were never finalized. See 53 Fed. Reg. 27267 (July 19, 1988). 

Most of the attention, however, focused on the release reporting issues, rather then the cleanup 

liability issues. 54 Fed. Reg. 29305, 29307 (July 11, 1989). EPA did observe in the preamble to the 

proposal that an “underground injection of hazardous substances permitted under an [authorized 

state or EPA program] is considered federally permitted for purposes of CERCLA notification.” 

(53 Fed. Reg. at 27273). EPA did not find it necessary to propose any amendments to the UIC 

program regulations. 

Having raised these CERCLA issues in its proposal, EPA should take the present opportunity to 

provide a regulatory clarification of the existing exemption from CERCLA cleanup liability for UIC 

projects. EPA should clarify that the scope of “authorized injection of fluids” which defines the 

FPR exemption should be provided by the definition of CO2 stream, which should define the scope 

of the permitted injection to include: 

[Any] carbon dioxide that has been captured from any source, plus incidental 

associated substances derived from the source materials or a capture process, and 

any substances added to the stream to enable or improve the injection process. 

73 Fed. Reg. at 43535, proposed 40 CFR §146.81(d), definition of “Carbon dioxide stream” (with 

our proposed modifications). For further clarification, EPA could provide that only the injection 

under a Class VI permit of streams failing to meet this definition would fall outside the scope of the 

“authorized injection of fluids” unless expressly authorized for injection in the permit covering the 

well. EPA should also address CERCLA § 107(j) and provide an appropriate clarification of the 

broad array of potential response costs or damages it would consider to result from an authorized 

UIC project, e.g. costs to address the migration of impurities, mobilized pre-existing contaminants, 

or displaced brines. 

Although the risk of a CO2GS project giving rise to CERCLA liability is relatively low, raising the 

prospect of any potential for CERCLA liability may be so chilling as to significantly curtail efforts to 

develop CO2GS projects. CERCLA’s far-reaching liability web and the tremendous costs that can 

be imposed on parties potentially liable under CERCLA are now well-known. Also well-known is 

the reluctance of businesses and investors to support projects faced with a potential for liabilities of 

a CERCLA-scale. For example, the impacts of CERCLA on the commercial/industrial property 

market in the late 1980’s and early 1990’s were devastating to many urban centers. To avoid 

incurring CERCLA liability, property owners and prospective purchasers simply avoided deals 

involving properties with any potential hazardous substance contamination. This contributed to the 

so-called “brownfield” problem of unused or underutilized properties being shunned due to 

potential or actual contamination, and the associated CERCLA liability concerns. This in turn led to 

the expansion of development to previously undeveloped “greenfields” sites that, while less risky 

from a CERCLA perspective, raised their own array of concerns such as urban sprawl, infrastructure 

costs, etc. In response to the negative impacts of potential CERCLA liability, EPA and many states 

have gone to great lengths over the last ten years to alleviate liability concerns and encourage 

brownfield development projects. Similarly, EPA should recognize the significant chilling effect that 

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CERCLA liability concerns would have on the development and deployment CO2GS projects, 

especially in this era of high volatility in the investment markets. EPA should use the opportunity in 

this rulemaking to alleviate unwarranted CERCLA liability concerns to the greatest extent possible. 

Even more troubling than the potential negative impact on the investment community is the threat 

of subjecting hundreds, thousands, and even more numerous pore space owners to CERCLA 

liability. Their property interests in potential deep subsurface CO2GS project injection zones could 

subject them to strict, joint, and several liability under CERCLA pursuant to liability theories that 

could be conjured up by future litigants seeking compensation for investigation response – and 

possibly remediation – costs claimed to be incurred as a result of releases from geologic 

sequestration injection zones. The discussion of what might be required to acquire any necessary 

rights to conduct CO2GS projects is complex enough already without even beginning to consider 

how the willingness of pore space owners to participate might be obliterated by the uncertainties of 

CERCLA liabilities hanging over their heads. 

In short, EPA needs to seize the opportunity to dispel the specter of CERCLA liability raised in its 

preamble by developing appropriate language to provide the clarity and assurance needed to 

promote continued research, development and deployment of CO2GS projects. 

E. EPA Should Ensure that the Regulations for GS Are Not More Stringent or 

Prescriptive than Necessary to Protect USDWs. 

EPA has recognized that it has two goals for the proposed rules for geologic storage of carbon 

dioxide: the protection of underground sources of drinking water2/ and the promotion of the 

development of carbon capture and storage.3/ EPA Administrator Stephen Johnson noted when he 

announced the proposal that “"[t]oday's proposal paves the way for technologies that would protect 

public health and help reduce the effects of climate change. With proper site selection and 

management, geologic sequestration could play a major role in reducing emissions of carbon dioxide 

into the atmosphere."4/

 We urge EPA to keep both of these goals in mind and to work to ensure 

that the regulatory regime that is ultimately adopted is designed to facilitate – not delay or discourage 

– the successful commercial-scale development of carbon capture and storage. The potential 

emissions benefits of commercial-scale carbon storage are too large and too important to ignore in 

the context of these regulations. 

 

2/ 73 Fed. Reg 43492 (July 25, 2008) (“It proposes a new class of well and minimum technical criteria for the 

geologic site characterization, fluid movement, area of review (AoR) and corrective action, well construction, operation, 

mechanical integrity testing, monitoring, well plugging, post-injection site care, and site closure for the purposes of 

protecting underground sources of drinking water (USDWs).”). 

3/ EPA Press Release, “EPA Lays Groundwork for Promising Technologies to Help Mitigate Climate Change” 

(July 15, 2008), http://www.epa.gov/safewater/uic/wells_sequestration.html (“EPA is proposing a rule that supports 

promising technologies to prevent industrial emissions of carbon dioxide. Secure, long-term underground storage of the 

greenhouse gas is one way scientific innovation could lessen the effects of climate change. . . . Carbon capture and 

storage is part of a portfolio of technologies available to reduce greenhouse gas emissions. EPA is coordinating with the 

Department of Energy on carbon sequestration research and development.”); EPA Press Release, “EPA To Develop 

Regulations for Geologic Sequestration of Carbon Dioxide” (October 7, 2007) Id. 

4/ EPA Press Release (July 15, 2008). 

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Unfortunately, in its effort to ensure protection of USDWs, EPA has exhibited a zeal that could 

materially impede, overburden, and effectively stigmatize GS. The preamble to the proposed rule 

repeatedly overstates the risks posed by CO2 injection while systematically understating the extent 

of knowledge and experience industry and regulators have gained through decades of practical 

experience with a wide range of injection well operations. As a result, the preamble presents an 

exhaustive review of every imaginable risk with respect to CO2 injection, but fails to disclose that 

many of these theoretical risks relate to implausible scenarios or concerns that – based on decades of 

robust operational and regulatory experience – are well understood and relatively easy to address. 

The scale of GS operations will certainly be larger than many previous CO2 injection operations, but 

it is not as though we do not have extensive experience with CO2 injection or that there is any 

fundamental lack of understanding about what happens when CO2 is injected underground. After 

all, there are already thousands of existing CO2 injection wells in operation that have injected 

hundreds of millions of tons of CO2 largely without incident. Rather than provide appropriate 

context for the development of Class VI regulations, however, the proposed rule gives the 

impression that GS is an adventure into entirely uncharted seas. The proposed rule – having started 

by framing the issues in this way – then employs a regulatory approach that errs on the side of 

including excessively prescriptive, overly-burdensome, and often redundant requirements. 

1. The Proposed Class VI Requirements Are Far More Burdensome than 

Necessary to Protect USDWs. 

As the preamble acknowledges, the actual human health and ecological risks associated with GS are 

relatively remote and can be addressed effectively through measures implemented to protect 

USDWs. 73 Fed. Reg. at 43497-98. Unfortunately, having started with an exaggerated sense of the 

risks involved and an inadequate recognition of the value of existing regulatory and operational 

experience relevant to CO2 injection, the proposed rule seems to proceed from the premise that the 

most strict UIC regulations in existence – those for hazardous waste injection – should serve as the 

starting point for the development of the Class VI regulations. This is not a logical or appropriate 

regulatory approach, because CO2 – which is found in abundance both in ambient air and in the 

subsurface – is nothing like hazardous waste and plainly does not warrant the same level of 

regulation. In fact, the principal issues with respect to CO2 injection for GS relate primarily to the 

mobility of CO2 and the sheer magnitude of the injection operations involved; these are not issues 

that the requirements for hazardous waste injection are particularly well suited to address. 

The more logical starting point for development of the Class VI regulations is the Class II 

regulations. As the proposed rule recognizes, CO2 injection operations have been conducted 

pursuant to the Class II regulations for many years, and experience with thousands of wells injecting 

hundreds of millions of tons of CO2 demonstrates that the Class II regulations – as applied to CO2 

injection – are adequate to protect USDWs. This is certainly true with respect to the basic 

construction, operating, monitoring, and mechanical integrity testing requirements for injection 

wells; after all, what “works” in terms of the construction and operation of a CO2 injection well 

does not depend on the purpose for which CO2 is being injected. Accordingly, there is no reason 

why the Class VI requirements addressing issues such as well construction and mechanical integrity 

testing should be any different than the Class II requirements. 

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Unfortunately, the proposed Class VI requirements are far more stringent than the Class II 

requirements, a fact that creates a need to “grandfather” Class II CO2 injection wells that remain in 

service for GS purposes after EOR/EGR operations cease. Rather than resembling the Class II 

requirements, the proposed Class VI requirements are as stringent as those for hazardous waste 

injection in most respects. Indeed, many of the construction, mechanical integrity, monitoring and 

financial assurance requirements proposed for Class VI wells are even more comprehensive and 

more strict than those for hazardous waste injection wells. While some of these more burdensome 

requirements are legitimately related to concerns about the mobility of CO2 or the anticipated scale 

of GS operations, many – as discussed in Part III of these comments – are not. 

2. Rules that Stigmatize GS or Burden it Excessively Would Not be in the 

Public Interest. 

The magnitude of the regulatory burdens imposed by the proposed Class VI requirements are of 

concern for several reasons. First, unnecessary regulatory burdens would act as a direct impediment 

and disincentive to the development of GS projects. Less directly, the imposition of unreasonably 

stringent regulatory requirements – particularly requirements for multiple layers of requirements 

addressing the same basic risks – inherently magnify the impression of risk and could thus stigmatize 

GS and discourage investment in GS projects. EPA should recognize that “more regulation” – 

particularly the “belt-and-suspenders plus more belts and more suspenders” approach reflected in 

the proposed rule – is not “better regulation” in the GS context. To the contrary, overlyburdensome regulation – to the extent it effectively impedes or deters use of a promising technology 

– could prove counterproductive. 

We understand the importance of public perception when it comes to the siting and permitting of 

needed infrastructure, and believe strongly in the need to ensure that the public has accurate 

information. To facilitate the public’s appreciation of the merits of GS, we urge EPA to ensure that 

it does not overstate the risks associated with CO2 injection or understate the justified confidence 

with which many potential issues and concerns can be addressed. Similarly, we urge EPA to avoid 

the imposition of regulatory requirements that are so disproportionate to the risks involved that they 

may do more to incite than address public concerns. To this end, EPA should scale back its 

regulatory requirements to more accurately reflect the magnitude of actual risks and to ensure that 

any requirements imposed are truly necessary for the protection of USDWs. 

EPA should also consider the effect its regulations might have on the ability to secure critical 

financial backing for GS projects. Any exaggerated impression of the risks involved in GS could 

adversely influence financial institutions and impede efforts to obtain financing. The recent turmoil 

in the financial markets highlights how challenging the financing of new technologies may become. 

In a credit-constrained world, investors will be wary of putting their limited funds behind GS 

projects if they believe they are likely to endanger the environment or public health. Accordingly, 

EPA should recognize the importance of the messages that it sends the financial world through the 

regulations it imposes. 

Permanent storage of CO2 can be accomplished safely and without harm to the environment as long 

as we apply the right knowledge base, detailed site-specific information, technical expertise, and 

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sound management practices. However, we cannot implement an effective regulatory program for 

sequestering CO2 if the rules are based on the erroneous premise that CO2 represents an extreme 

hazard. It is therefore important that EPA send accurate messages about the nature of CO2 and the 

actual magnitude of the risks associated with GS. It is also critical that EPA strike an appropriate 

balance by addressing the risks associated with GS without creating a regime that effectively hinders 

or deters use of this key technology for reduction of carbon emissions. 

III. Comments Regarding Proposed Class VI Requirements

A. Geologic Siting Requirements

In view of the need to promote appropriate use of GS to reduce CO2 emissions, the regulations 

should be designed to allow GS in any geologic setting in which the Director concludes that GS 

can be conducted without endangering USDWs. It follows that the regulations should give the 

Director discretion to apply the “non-endangerment” performance standard on a site-specific 

basis as particular geologic site conditions warrant, without the need to apply prescriptive criteria 

that – while perhaps necessary to endure protection of USDWs in some cases – would arbitrarily 

disqualify some sites that would in fact be appropriate for GS. This does not mean that 

regulation need be lax; it simply means that regulation must be flexible, and that rigid criteria 

should not substitute for performance-based standards and site-specific consideration of the 

merits. 

The preamble to the proposed rule outlines normal site selection criteria for injection well 

projects, including the need to identify an injection zone with sufficient permeability, porosity, 

thickness and lateral extent and a low-permeability confining zone with sufficient thickness and 

lateral extent to protect overlying USDWs. 73 Fed. Reg. at 43505. These are familiar and 

appropriate geologic siting requirements for injection well operations, and the regulatory text 

proposed for codification at 40 C.F.R. 146.83(a) – with relatively minor technical changes – 

would embody them appropriately. Unfortunately, the preamble goes on to suggest the need for 

overly-elaborate analysis of extraneous issues, and the rule text proposed for codification at 40 

C.F.R. 146.83(b) would allow the Director apparently unlimited discretion to impose siting 

conditions that go beyond those necessary to ensure protection of USDWs. EPA should clarify 

that site evaluation should go no farther than necessary to prevent endangerment, and should 

eliminate any apparent discretion to impose siting requirements that are not necessary to protect 

USDWs. 

1. Site Evaluation

The preamble appears to suggest the need for an elaborate evaluation of site conditions to 

address concerns related to seismicity and potential geochemical interactions. In fact, however, 

seismicity and geochemical impacts are issues that are easily addressed in the GS context, and 

requirements for unnecessarily elaborate analysis would serve only to burden and impede the 

development of GS projects. 

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Concerns with respect to seismicity are frequently raised in the injection well context, but there 

is ample experience demonstrating that such risks are modest and easily addressed through 

appropriate injection pressure limitations. Similarly, geologic compatibility – while it can 

present issues in some contexts – is unlikely to present any serious problems in the GS context. 

These conclusions are confirmed by decades of experience with literally thousands Class II CO2 

injection wells injecting hundreds of millions of tons of CO2. 

The apparent extent of concern about geochemical compatibility is particularly hard to 

understand. Although it is true that injection of CO2 can be expected to lead to the formation of 

carbonic acid, the resulting carbonic acid is only weakly corrosive and – as experience with the 

injection of extremely corrosive hazardous wastes demonstrates – cannot reasonably be expected 

to cause any breach of containment that would endanger a USDW. The proposed rule expresses 

specific concern about geochemical reactions that could alter the composition of the injected 

CO2 stream – particularly through the mobilization of contaminants that occur naturally in the 

injection zone – but such concerns are essentially immaterial because the specific composition of 

the CO2 stream matters little as long as the CO2 stream remains confined. 

2. Redundant Confining/Containment Zone Requirement

EPA requests comment on whether the Final Rule should require, or allow the Director 

discretion to require, additional confining and containment zones above the primary confining 

zone. 73 Fed. Reg. at 43505-06. We oppose any such requirement. 

If there are substantial doubts as to the adequacy of a single confining formation, it would of 

course be necessary to specify one or more additional formations as part of the a confining 

system that would be adequate to protect USDWs; this is one of the reasons the term “confining 

zone” is defined in the way it is (i.e., to include a “geologic formation [or] group of formations” 

acting as a barrier to fluid movement). Considerations as to the adequacy of the confining zone 

are a central focus of the permitting process, with permit applicants being required to 

demonstrate that USDWs will not be endangered by the proposed injection activity. By 

definition, a requirement for additional confining zones would therefore be a requirement for 

redundant geologic containment: it would never be necessary for the protection of USDWs. By 

allowing the Director discretion to impose such a requirement, the proposed rule would expressly 

authorize the imposition of requirements that are not necessary for the protection of USDWs. 

Worse, the proposed rule provides no apparent limit on the Director’s discretion in this regard. 

Indeed, the preamble suggests that the Director could require detailed evaluation of additional 

geologic formations just because they are there, perhaps in the hope that additional study and 

documentation – though not necessary to show that USDWs will be protected – might “improve 

public confidence in and acceptance of” GS. 73 Fed. Reg. at 43506. 

Again, the ultimate standard for geologic citing should be protection of USDWs. By authorizing 

extraneous siting (or site assessment) requirements that are not necessary for protection of 

USDWs, the proposed rule would invite a “belt and suspenders” approach that would 

unnecessarily burden permit applicants and signal unwarranted concern about the risks and 

uncertainties associated with CO2 injection. Under the UIC program, protection of USDWs is 

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and should be enough. The Director should have no discretion – let alone unlimited discretion – 

to “tack on” additional siting requirements. 

It should be noted that a requirement for redundant confining and containment zones would be 

unprecedented. No such requirement exists in the UIC program, even in the context of 

hazardous waste injection. Nor does such a requirement apply in any of the countries where GS 

projects are currently underway (including Norway, Canada, Australia and Algeria). EPA 

should not single out GS for heightened and substantially more rigorous requirements than 

would apply in other contexts. To do so would signal a disproportionate concern about the 

injection of CO2 that simply is not warranted on the merits. 

B. Area of Review and Corrective Action Requirements

We support the use of computational models for determination of the appropriate area of review 

(“AOR”) for GS purposes. Modeling of the pressure effects associated with injection – together 

with conservative modeling to bound the potential extent of CO2 plume movement – are 

appropriate aids to the evaluation of geologic siting and corrective action to address risks 

presented by artificial penetrations such as abandoned boreholes. The use of such modeling is 

already well-established in the context of oil and gas exploration and production and has been 

used in the UIC program for “no-migration” petitions for hazardous waste injection. Similar 

modeling can reasonably be adopted for use in the GS context as well. 

1. AOR Definition

The proposed rule vaguely defines the AOR as “the region surrounding” the GS project that 

“may be impacted by the injection activity.” 72 Fed. Reg. at 43535 (proposed 40 C.F.R. 

146.81(d)). The definition goes on to suggest that the AOR is to be “based on computational 

modeling that accounts for the physical and chemical properties of all phases of the injected 

carbon dioxide stream.” Id. There are three issues. 

First, the proposed definition suggests the need for a more complex modeling approach than may 

typically be necessary or appropriate. As experience with hazardous waste injection “no 

migration” petitions shows, it is rarely necessary to attempt to model chemical changes in the 

injectate plume; instead conservative modeling of transport should typically be sufficient by 

itself to show that USDWs will not be endangered. Where this is the case, it is containment of 

the injectate plume – rather than the precise composition of the plume – that matters and there is 

no need to model chemical changes. This is a critical point, because it is generally far easier to 

model transport than chemical changes occurring in the subsurface. In fact, it would be 

extraordinarily burdensome to have to model “the chemical properties of all phases of the 

injected carbon dioxide stream” as the proposed rule suggests. Such modeling should be 

required only to the extent that it is truly necessary to ensure that USDWs will be protected. 

Second, the preamble to the proposal suggests that the “best” (most sophisticated?) and most 

“accurate” modeling should be preferred or even required. 73 Fed. Reg. at 43507. However, 

fine precision generally isn’t necessary, The appropriate goal for modeling is to ensure 

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protection of USDWs, and conservative (i.e., less precise) modeling may be sufficient and even 

preferable for this purpose. A quest for greater precision would not guarantee greater confidence 

in modeling results, and could effectively require a less conservative – and thus potentially less 

protective – modeling approach. 

Third, the functional purpose of the AOR is to define the area within which impacts of the 

injection activity could cause endangerment of a USDW; specifically, the AOR defines the area 

within which corrective action for abandoned boreholes may be necessary to prevent 

endangerment of USDWs. The language of the proposed rule (i.e., “may be impacted by the 

injection activity”) is not clearly limited to impacts of the injection activity that could cause 

endangerment of USDW’s. It should be. 

2. Corrective Action

Corrective action is a familiar UIC program requirement. Given the potential scale of GS 

operations, EPA has proposed requirements for a corrective action plan contemplating a phased 

implementation of corrective action. In general, this approach is prudent and practical, providing 

a rigorous approach to corrective action while reducing regulatory burdens by permitting a 

phased implementation of corrective action requirements. 

3. AOR Reevaluation

The proposed rule requires periodic reevaluation of the AOR determination on a frequency of at 

least once every ten years. We recommend an alternative approach. 

Reevaluation of the AOR is a significant exercise that ought to be triggered only when 

information suggests that there is actually a need for reevaluation. At the same time, it is 

important to recognize that injection well operations provide an ongoing stream of information – 

injection pressure information in particular – that might suggest the need for reevaluation of the 

AOR. Consequently, it does not make sense to require reevaluation of the AOR on any fixed 

schedule; instead, it makes sense to consider the need to reevaluate the AOR on a regular basis, 

and to reevaluate the AOR if – but only if – there is evidence of a need to do so (i.e., if 

information becomes available that is materially inconsistent with assumptions underlying an 

existing AOR determination). 

The proposed rule would already require a semi-annual report of injection operations. 73 Fed. 

Reg. at 43540. We recommend that these periodic reports be annual, consistent with Class II 

requirements, and that these reports include an assessment of the need for reevaluation of the 

AOR. Specifically, we support the Ground Water Protection Council’s CO2 Committee 

recommendation 7.6 that operators: 

Report annually, or at a frequency acceptable to the Director, the characteristics 

and cumulative volumes (annual and total) of injected fluids, injection pressures, 

injection rates, annular pressures for each injection well, the results of any 

mechanical integrity tests conducted during this time period, available site 

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integrity monitoring results, the extent of the injected CO2 and the pressure front 

based on current data. 

 

Update site operations as appropriate and site modeling results annually, or at a 

frequency acceptable to the Director, to reflect current data. Compare the updated 

results to the previous results. Identify and explain to the Director any 

discrepancies between the updated results and the previous results. 

This approach will provide a reasonably frequent consideration of the need for reevaluation of 

the AOR, ensuring that the AOR is reevaluated promptly when necessary but that there is no 

need to reevaluate the AOR when monitoring results remain consistent with modeling results 

such that a requirement to reevaluate the AOR would be unnecessary. 

C. Injection Well Construction Requirements

1. Well Design

Many years of experience with the Class II UIC program – including 35 years of CO2 injection 

in the EOR context – have demonstrated that the construction requirements for Class II injection 

wells are sufficient to ensure that injected fluids cannot escape from the intended injection zone 

via the injection well borehole. The proposed rule would nevertheless impose substantially more 

costly well construction requirements resembling those for Class I hazardous waste injection 

wells. The Proposed Rule specifically cites the buoyancy of CO2 as the justification for these 

requirements. See 73 Fed. Reg. at 43509. 

The buoyancy of CO2 in no way justifies the additional construction requirements proposed. 

The reason for this is straight-forward: by far the greatest driving force for fluid migration along 

an injection well borehole is the pressure build-up (or “cone of influence”) caused by fluid 

injection during the operation of the injection well. The magnitude of this pressure influence is 

at its maximum at the point of injection, and – within the injection interval – it generally falls off 

logarithmically with lateral distance from the injection well borehole. At some distance from the 

injection well, the pressure influence of the injection activity can be expected to decline to the 

point where density-driven flow (i.e., buoyancy) could become significant (at least in relative 

terms) as a driver for vertical fluid migration. At the injection well, however, the induced 

pressure gradient caused by the injection activity would so dwarf the impact of buoyancy as to 

render the latter insignificant. Accordingly, it would be unreasonable to suggest that buoyancy 

justifies significantly more demanding injection well construction requirements than have 

already proven to be sufficient in the case of Class II CO2 injection wells. 

Our specific recommendations with respect to well construction are as follows. 

EPA should rely primarily on the basic performance standards for well construction stated 

in proposed 40 C.F.R. 146.86(a) rather than on less flexible well design specifications. This 

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approach has proved effective in the context of the Class II program, and leaves permit-writers 

free to tailor well construction requirements to the particular circumstances involved. 

EPA should delete the proposed design requirement for a surface casing cemented from the 

base of USDWs to the surface. While this is a commonly-imposed requirement and is 

generally appropriate, there are some conditions (e.g., when the base of the lowermost USDW is 

particularly deep) where such a requirement would be unduly burdensome and inappropriate. 

Accordingly, the need for surface casing to extend all the way through the base of the lowermost 

USDW should be left to the discretion of the permit writer rather than being predetermined in the 

text of the rule. 

EPA should delete the proposed design requirement for the long-string casing to be 

cemented to the surface. Such a requirement – while arguably appropriate in the case of 

hazardous waste injection wells – can significantly complicate well construction, testing and 

repair, and is too costly to justify in the case of CO2 injection. Cement must of course be 

sufficient to prevent endangerment of USDWs, but the specific measures necessary to achieve 

this performance standard are dependent on site-specific conditions and are most appropriately 

determined in the permitting process rather than being predetermined in the text of the rule. 

EPA should retain the requirement for injection through a tubing and packer to facilitate 

continuous monitoring of a pressurized annulus. Wells designed with tubing and packer 

effectively provide two barriers, both of which must be breached before injectate could leave the 

borehole. At the same time, this design permits a proven method of monitoring that would 

permit detection of a breach in either barrier so that repairs can be made before both barriers fail. 

And a requirement to maintain positive pressure on the annulus, rather than always maintaining 

the annulus pressure in excess of the injected fluid pressure in the injection tubing will be 

sufficient as CO2 is not hazardous waste.

2. Materials of Construction

Besides specifying additional construction requirements, the proposed rule would require the use 

of degradation-resistant construction materials such as acid-resistant cement and a corrosionresistant casing. 73 Fed. Reg. at 43510. These requirements are based on the premise that CO2 

is corrosive and that experience with CO2 injection in the EOR context suggests that corrosion is 

a significant issue. 73 Fed. Reg. at 43509-10. 

In fact, CO2 is not corrosive. What is corrosive is carbonic acid formed through the interaction 

of CO2 and water. This distinction is critical from a practical standpoint, because injected CO2 

streams would at least generally be “dry” (i.e., dehydrated) and therefore non-corrosive. Once 

injected, the “dry” CO2 would come into contact with naturally-occurring water in the 

subsurface, creating carbonic acid. However, an injection well would inject CO2 far more 

rapidly than the CO2 could mix with water, creating a CO2 plume that would immediately 

displace water away from the point of injection. While some residual water saturation would 

remain, the potential for carbonic acid formation in the immediate vicinity of the injection well 

would be limited. In this situation – which can be expected to be typical in the carbon 

Carbon Sequestration Council (CCS Contact Group) 20 bdday@bryancave.com 
Docket ID No. EPA–HQ–OW–2008–0390 

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sequestration context – there is no basis to suggest that injected CO2 is corrosive or that injection 

wells must be designed and constructed to resist a severely corrosive environment. 

Class II experience with CO2 injection supports this conclusion. Corrosion is sometimes an 

issue for injection wells used to produce “wet” streams containing oil, brine, and CO2 fractions 

brought up in the course of EOR/EGR operations. However – and this is the relevant point in the 

GS context – “dry” CO2 injection systems have operated for many years without the need for 

corrosion-resistant construction or the occurrence of corrosion-related problems. 

Well construction requirements under the UIC program generally require that operational 

conditions and the nature of formation fluids and proposed injectate be considered in well 

construction, and these general requirements have served well. Thus, while there may be some 

Class VI CO2 injection scenarios in which corrosion-resistant materials may be required, there is 

no technical basis for any general presumption that they are necessary or should be required. 

It should also be noted that the choice of casing and cement materials should be based on 

planned operating life of the injection well, not the ultimate duration of the GS program. The 

potential for longer term exposure of well components after injection has ceased will depend 

upon – and can be mitigated by – measures implemented at closure, such as plugging. 

D. Logging, Sampling and Testing Prior to Injection Well Operation

While we have other specific concerns that are addressed in our detailed comments, our principal 

concern is that the logging, sampling and testing requirements of the proposed rule are overly 

rigid and prescriptive. In particular, the proposed rule appears to proceed from the premise that 

all of the information that could usefully be obtained from the logging, sampling and testing of a 

borehole should be obtained from the logging and testing of every borehole. Such an approach 

would be wasteful and unnecessarily burdensome. 

Our concerns are particularly acute with respect to the formation sampling and testing 

requirements specified in proposed section 40 C.F.R. 146.87(b) and (d). While there are likely to 

be cases in which very little site-specific information is available prior to drilling, there will be 

other cases in which vast amounts of information are or will be available and the incremental 

value of another exhaustive set of logs, samples and tests would be minimal. For example, 

extensive logging, sampling and testing clearly should not be necessary where there are multiple 

other injection wells or stratigraphic test wells that have been (or are being) used to gather the 

same kind of information for the same geologic formations and the same area. Accordingly, it is 

important to ensure that logging and testing requirements be tailored to the circumstances 

involved so that that costly and duplicative logging, sampling and testing requirements can be 

avoided. 

Carbon Sequestration Council (CCS Contact Group) 21 bdday@bryancave.com 
Docket ID No. EPA–HQ–OW–2008–0390 

 December 23, 2008 

E. Injection Well Operating Requirements

1. Injection Pressure Limitations

We support the discussion and recommendation on injection pressure limitations presented in the 

Joint Letter resulting from the multi-stakeholder discussion. 

2. Pressurized Annulus

The proposed rule would require a pressurized annulus with an annulus pressure exceeding the 

pressure in the injection tube. While we support the proposed requirement for a pressurized 

annulus, we oppose the requirement that annulus pressure exceed injection tube pressure. 

The concept that annulus pressure should exceed injection tube pressure was introduced in the 

context of hazardous waste injection, where it reflected an extreme sensitivity to even the most 

remote possibility of a release of hazardous waste (the requirement was designed to ensure that 

injection tube leaks would cause annulus fluid to leak into the injection tube rather than allowing 

injectate to enter the annulus). The same extreme level of sensitivity obviously isn’t warranted 

in the context of CO2 injection; as a result, the additional operating and maintenance costs 

typically needed to maintain an over-pressurized annulus would not be justified. 

A pressurized annulus would permit detection of casing leaks whether or not annulus pressure 

exceeds injection pressure. Similarly, any significant pressure differential between in annulus 

and injection pressure would permit prompt detection of a tubing leak whether or not annulus 

pressure exceeds injection pressure. Accordingly, a requirement for a pressurized annulus is 

sufficient to protect USDWs without any requirement that annulus pressure exceed injection 

pressure. Indeed, a requirement that annulus pressure exceed injection pressure could - 

depending on the site conditions involved – do more to limit than enhance the sensitivity of leak 

detection. Consequently, the determination of annulus pressure should be left to the permitting 

process, without any presumption in favor of an over-pressurized annulus. 

3. Continuous Monitoring

As already indicated, we support continuous annulus and injection pressure monitoring for leak 

detection purposes. Continuous monitoring of injection rate, volume, and injectate temperature 

is also appropriate, but the proposed requirement for continuous monitoring of annulus fluid 

volume is unnecessary and (depending on what is actually contemplated) impractical. There is 

ample UIC program experience demonstrating that continuous monitoring of annulus fluid 

volume is not required for any purpose. For leak detection, pressure monitoring – with periodic 

records of annulus fluid additions and withdrawals – has proved to be sufficient. 

4. Down-Hole Shut-Off Valves

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 December 23, 2008 

EPA proposes to require automatic shut-off valves down hole as well as at the surface. Such a 

requirement is unnecessary and would be costly and completely unprecedented in the UIC 

program. In fact, the “down-hole” valves EPA is referring to are designed for off-shore use, and 

are intended to provide a shut off point below the sea bed in the event of a casing breach between 

the sea bed and the surface. Such valves are not appropriate for use deep under ground, and their 

use as proposed would increase well construction and operation costs and significantly 

complicate well testing and workovers. 

In any event, there is simply no justification to require the use of down-hole shut-off valves in 

the CO2 injection context. Class I hazardous waste injection wells are not required to have 

down-hole automatic shut-off valves, and there is no basis at all to suggest that CO2 injection 

entails higher risks warranting such costly and problematic measures. 

5. Corrosion Monitoring

As already discussed, CO2 is not corrosive in the absence of water and there is no basis to 

assume that GS wells will typically be used to inject corrosive fluids or will always be in contact 

with corrosive conditions in the injection zone. A general requirement for corrosion monitoring 

is therefore unnecessary and inappropriate. 

Even if there were some basis for corrosion concerns, a requirement for corrosion monitoring 

would be excessive, because the proposed rule already includes other provisions sufficient to 

address the risks corrosion would present. In particular, the proposed rule would require that 

injection wells be designed and constructed for their intended service. This requirement would 

address the potential for corrosion even if (as we recommend) the burdensome and unnecessary 

provisions expressly requiring use of corrosion-resistant materials is excised. In addition, the 

requirements for a tubing and packer design would protect against corrosion leaks, both by 

providing secondary containment of the injectate and by permitting continuous annulus pressure 

monitoring (also required) to ensure that corrosion leaks could be detected and repaired before 

both layers of containment would be breached. 

6. Injection Depth

As already discussed, we oppose restricting Class VI injection to either to any minimum 

injection depth or to injection zones below the lowermost USDW. As EPA recognizes, 73 Fed. 

Reg. at 43511-12, such restrictions are not necessary to protect USDWs and would serve only to 

preclude the use of what might otherwise be appropriate CO2 storage reservoirs. EPA should 

permit GS under any circumstances in which the Director can determine that USDWs will not be 

endangered. 

Recognizing that the USDW definition is so broad as to include formations that – because of 

their location, depth, or other factors – could not reasonably be expected to serve as sources of 

drinking water, we support the appropriate use of aquifer exemptions to facilitate GS. 

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 December 23, 2008 

7. Tracers

We strongly oppose any requirement for the use of tracers, including any such requirement that 

could be imposed at the discretion of the Director. 

There are at least two fundamental issues with respect to tracers. First, tracers are unlikely to 

enhance the protection of USDWs. This is true not just because the Class VI regulations are 

designed to minimize the likelihood of the kind of leakage tracers would ostensibly help detect, 

but because – even in the event of such a leak – tracers are not likely to be especially useful in 

leak detection (as discussed in the context of monitor wells, fluid monitoring in the deep 

subsurface provides only very localized information and is unlikely be very effective in leak 

detection whether or not tracers are used). Second, tracers are at least as likely to create “false 

positives” as to aid in the detection of actual down-hole leaks. The problem in this respect is 

simple: it is much easier for accidental leaks and releases to occur in the surface environment 

than in the deep subsurface. 

A final consideration is perhaps the most obvious: a requirement for tracers would be unique in 

the UIC program, and would unavoidably undermine public confidence in permitting 

determinations that – by definition – would be based on the premise that leaks from injection 

wells and properly permitted injection formations are extraordinarily unlikely to occur. 

F. Mechanical Integrity Testing (MIT) Requirements

The proposed rule suggests that “MIT requirements for GS wells should be tailored to address 

the unique properties of CO2, specifically its buoyancy and potential corrosivity.” 73 Fed. Reg. 

at 43513. As previously discussed, however, the buoyancy of C02 is a relatively trivial factor in 

relation to the cone of influence created by injection pressure during injection, a factor that 

makes buoyancy virtually irrelevant as a driving force for upward migration through the 

injection well borehole during the operational life of a GS well. Accordingly, there is no basis to 

suggest that the buoyancy of CO2 is a significant factor to consider in establishing mechanical 

integrity testing requirements for GS wells. Similarly – as also previously discussed – CO2 is 

not corrosive and cannot be expected to cause substantial corrosion problems for the injection 

well (including down-hole cement) unless the CO2 stream itself contains water. Consequently, 

concerns related to corrosion do not justify particularly stringent MIT requirements for GS wells. 

Experience with CO2 in the EOR context fully supports these conclusions. In fact, the Class II 

MIT requirements have been sufficient for CO2 injection in the EOR/EGR context, and there is 

no reason why they should not be sufficient in the GS context as well. Accordingly, the 

proposed MIT requirements for Class VI wells are more stringent and prescriptive than 

necessary. 

As already indicated, we support the requirement for continuous injection and annulus pressure 

monitoring as a means to ensure “internal” mechanical integrity. With regard to “external” 

mechanical integrity, we believe that the test methods employed and the frequency of testing 

should be within the discretion of the permit writer, subject only to a requirement that external 

Carbon Sequestration Council (CCS Contact Group) 24 bdday@bryancave.com 
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mechanical integrity be demonstrated through approved MIT techniques at least once every five 

years. 

G. Testing and Monitoring Requirements

The preamble to the proposed rule indicates that “EPA considers CO2 plume and associated 

pressure front monitoring to be necessary for verification of model predictions.” 73 Fed. Reg. at 

43514. This proposal unnecessarily undermines confidence in the modeling demonstrations that 

can and should be relied upon to support determinations that injected CO2 will not endanger 

USDWs. Modeling provides a conservative assessment of the potential for movement of 

injected fluids in the subsurface, not a precise “prediction” of actual fate and transport that can or 

should be “verified” on the basis of elaborate, costly, and uncertain efforts to observe the actual 

movement of fluids in the subsurface. As experience with hazardous waste injection shows, 

injection well operational data and the results of pressure fall-off tests provide ample data to 

validate the results of modeling. The additional monitoring requirements proposed in the GS 

context go beyond what is required for Class I hazardous waste injection wells; these 

requirements are excessive and unnecessary. 

1. Monitoring CO2 Movement and Reservoir Pressure

The preamble to the proposed rule specifically states that the “[m]onitoring of subsurface 

geochemistry and the position of the CO2 plume and pressure front are necessary to verify 

predictions of plume movement, provide inputs for modeling, identify needed corrective actions, 

and target geochemical and surface monitoring activities.” 73 Fed. Reg. at 43514. Again, this is 

inconsistent with experience with Class I hazardous waste injection, where such monitoring has 

not been necessary and is not required. 

a. Monitor Wells

Monitor wells reaching the deep subsurface are problematic in a variety of respects. They are 

expensive to install, create potential pathways for vertical fluid migration, and – in the deep 

subsurface where natural fluid movement may be very slow or effectively non-existent – they 

have little potential to provide more than an isolated “point measurements.” Monitor wells also 

have built-in confounding factors that include both the potential for well construction to impact 

fluid quality in the target sampling interval and the fact that sampling may itself cause fluid 

movement that might not otherwise occur. Because pressure fronts extend much further than 

injected fluid plume fronts during injection, pressure monitoring is more likely to be useful than 

fluid sampling, but costs would still be very high and the ability to detect relevant changes would 

still be difficult. For these reasons, EPA chose not to impose monitor well requirements on other 

classes of injection wells, though it did allow monitor wells to be used for Class I hazardous 

waste injection wells at the discretion of the Director to address particular circumstances at the 

site. See 52 Fed. Reg. 32446 at 32463-64 (August 27, 1987), 53 Fed. Reg. 28118 at 28141, 

28144-45 (July 26, 1988). Experience with hazardous waste injection does not commend the use 

of monitor wells even in that context, and there is no justification to impose a more stringent an 

Carbon Sequestration Council (CCS Contact Group) 25 bdday@bryancave.com 
Docket ID No. EPA–HQ–OW–2008–0390 

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approach for the injection of CO2. Accordingly, we recommend that the potential for gaining 

useful information from monitor wells be carefully considered in developing an appropriate 

monitoring plan and that such wells be used only as justified by specific circumstances. (See 

Attachment A, 146.90(a).) 

b. Geophysical Methods for Plume Tracking

As an alternative to monitor wells, the proposed rule suggests that it may be possible to use 

remote geophysical techniques for “plume tracking.” 73 Fed. Reg. at 43515. Unfortunately, the 

technologies available would be very expensive to employ on the scale required. Seeking to 

achieve greater precision can lead to an expensive and unnecessary quest. 

2. Surface Air and Soil Gas Monitoring

The goal of any UIC program regulations for GS should be to ensure that injected CO2 streams 

remain confined in the subsurface and do not endanger underground sources of drinking water. 

We are recommending sufficient requirements to ensure that this goal is achieved. As EPA 

seems to recognize, surface air or soil gas monitoring would impose substantial costs and the 

results of such monitoring would be subject to a host of confounding factors. Worst of all, such 

monitoring would be aimed at leakage of CO2 all the way to the surface, which – in the case of 

any properly-permitted GS project – would by definition be an extraordinarily low probability 

scenario. Accordingly, such requirements should not be imposed, nor should regulators have 

discretion to impose them. If there is any serious concern that injected CO2 might actually vent 

to the surface in a particular location, injection should not be permitted at that site in the first 

place. The regulations should not suggest otherwise. 

Carbon Sequestration Council (CCS Contact Group) 26 bdday@bryancave.com 
Docket ID No. EPA–HQ–OW–2008–0390 

 December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 27 bdday@bryancave.com 

H. Financial Assurance

We support EPA’s flexible approach on financial assurance methods. It would be a mistake to 

impose any regulatory restrictions that would preclude the use of particular types of financial 

assurance or particular instruments, regardless of whether those are currently used for other 

classes of injection wells or in other EPA programs. Allowing for flexibility recognizes that 

operators are likely to use combinations of approaches and instruments to meet these 

requirements and that these combinations may change significantly over time as operators, 

program Directors and the financial markets gain more experience with geologic sequestration 

projects. EPA’s is wise to avoid any artificial constraints on the development of potentially 

acceptable means of achieving financial assurance. We recommend that this approach be 

retained in the final rule. 

Respectfully, 

Robert F. Van Voorhees 

Barton D. Day 

George F. Murphy 

Counsel to the Carbon Sequestration Council (CCS Contact Group) 

Bryan Cave LLP 

700 Thirteenth Street, N.W. 

Suite 700 

Washington, D.C. 20005-3960 

Phone: 202.508.6014 

Fax: 202.220.7314 

rfvanvoorhees@bryancave.com
1 

335843.7 

Attachment A: Comments and Recommendations of the Carbon Sequestration Counci

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

Part 144 1. The authority citation for part 144 continues to read as 

follows: 

Authority: 42 U.S.C. 300f et seq.; Resource Conservation 

and Recovery Act, 42 U.S.C. 6901 et seq. 

No comment 

144.1 2. Section 144.1 is amended as follows: 

Adding new paragraph (f)(1)(viii); and b. Revising the first two sentences in paragraph (g) introductory text. * * * * * (f) * * * (1) * * * (viii) Subpart H of this part sets forth requirements for owners or operators of Class VI injection wells. * * * * *  (g) Scope of the permit or rule requirement. The 

UIC Permit Program regulates underground injections by 

six classes of wells (see definition of ‘‘well injection,’’ § 144.3). The six classes of wells are set forth in § 144.6. All owners or operators of these injection wells must be authorized either by permit or rule by the Director. * * * 

Support revision to include a sixth class of wells

144.6 Add new paragraph (b)(4) 

 (4) For enhanced recovery of oil o

where geologic sequestration is occurring connection with enhanced recovery of oil oprovided (i) there is reasonable expectation insignificant future production volumes or rates carbon dioxide injection and (ii) operating preshigher than reasonably necessary to produce or rates; 
Carbon Sequestration Council (CCS Contact Group) 2 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

144.6 3. Section 144.6 is amended as follows: 

Revising paragraph (e); and b. Adding new paragraph (f). * * * * *  (e) Class V. Injection wells not included in Class I, II, III, IV, or VI. Specific types of Class V injection wells are described in § 144.81.  (f) Class VI. Wells used for geologic sequestration 

of carbon dioxide beneath the lowermost formation containing a USDW. 

Sections 144.6, and 146.5 – Classification of W (f) Class VI. Wells injecting a carbon dfor geologic sequestration except those wells subsection (b)(4) of this section or otherwise ethis Class.
Carbon Sequestration Council (CCS Contact Group) 3 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

144.15I 4. Adding § 144.15 to read as follows. 

§ 144.15 Prohibition of non-experimental Class V wells for geologic sequestration.  The construction, operation or maintenance of any non-experimental Class V geologic sequestration well is prohibited. 

Delete this provision. 

144.18 5. Adding § 144.18 to read as follows. 

§ 144.18 Requirements for class VI wells.  Owners or operators of Class VI wells must obtain a permit. Class VI wells are not authorized by rule to inject.

Support the proposed language. 

144.36 6. Section 144.36 is amended by revising the first two 

sentences in paragraph (a) to read as follows: § 144.36 Duration of permits.  (a) Permits for Class I and V wells shall be effective for a fixed term not to exceed 10 years. UIC Permits for 

Class II, III and VI wells shall be issued for a period up to the operating life of the facility. * * * * * * * * 

 (a) Permits for Class I and V wells shafor a fixed term not to exceed 10 years except for geologic sequestration. UIC Permits for C

and VI wells shall be issued effective for a pe

operating life of the facility. Permits for Class Vother wells used for geologic sequestration of shall be effective for the period through site clos
Carbon Sequestration Council (CCS Contact Group) 4 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

144.39 7. Section 144.39 is amended by revising the 

second sentence in paragraph (a) introductory text and by revising the second sentence in paragraph (a)(3introductory text to read as follows: 

) 

These sections may require further revisionconforming language. 

§ 144.39 Modification or revocation and reissuance of permits. * * * * *  (a) * * * For Class I hazardous waste injection wells, Class II, Class III or Class VI wells the following may be causes for revocation and reissuance as well as modification; and for all other wells the following may be cause for revocation or reissuance as well as modification when the permittee requests or agrees. * * * * * * * *  (3) * * * Permits other than for Class I hazardous waste injection wells, Class II, Class III or Class VI wells 

may be modified during their terms for this cause only as follows: * * * * * * * * 

144.51 8. Section 144.51 is amended by revising the first 

sentence in paragraph (q)(1) and the first sentence in paragraph (q)(2) to read as follows: § 144.51 Conditions applicable to all permits. * * * * *  (q) * * *  (1) The owner or operator of a Class I, II, III or VI well permitted under this part shall establish mechanical integrity prior to commencing injection or on a schedule determined by the Director. Thereafter the owner or operator of Class I, II, and III wells must maintain mechanical integrity as defined in § 146.8 and the owner or operator of Class VI wells must maintain mechanical integrity as defined in § 146.89 of this chapter. * * *  (2) When the Director determines that a Class I, II, 

III or VI well lacks mechanical integrity pursuant to § 146.8 

 (q) (1) The owner or operator of a Claswell permitted under this part shall establis

integrity prior to commencing injection or odetermined by the Director. Thereafter the ownof Class I, II, and III wells must maintain mechaas defined in §146.8 and the owner or operatowells must maintain mechanical integrity a§146.89 of this chapter. 
Carbon Sequestration Council (CCS Contact Group) 5 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

or § 146.89 for Class VI of this chapter, he/she shall give written notice of his/ her determination to the owner or operator. * * * * * * * * 

144.52 9. Section 144.52 is amended by revising 

paragraph (a)(8) to read as follows: § 144.52 Establishing permit conditions.  (a) * * *  (8) Mechanical integrity. A permit for any Class I, II, III or VI well or injection project which lacks mechanical integrity shall include, and for any Class V well may include, a condition prohibiting injection operations until the permittee shows to the satisfaction of the Director under § 146.08 or § 146.89 for Class VI that the well has mechanical integrity. * * * * * 

Support the proposed language. 

144.55 § 144.55 Corrective action. 

 (a) Coverage. Applicants for Class I, II, (other than 

existing), III or VI injection well permits shall identify the location of all known wells within the injection well’s area of review which penetrate the injection zone, or in the case of Class II wells operating over the fracture pressure of the injection formation, all known wells within the area of review penetrating formations affected by the increase in pressure. Applicants for Class VI shall perform corrective action as specified in § 146.84.* * * * * * * * 

Support the proposed language. 

144.80 11. Section 144.80 is amended by revising the 

first sentence in paragraph (e) and by adding paragraph (f) to read as follows: § 144.80 What is a Class V injection well? * * * * * 

(b) Class II. Classification of Wells: 

 (b) Class II. Wells which inject flui

enhanced recovery of oil or natural gas; (3) Fhydrocarbons.... and 

 (4) For enhanced recovery of oil o

where geologic sequestration is occurring connection with enhanced recovery of oil o
Carbon Sequestration Council (CCS Contact Group) 6 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

provided (i) there is reasonable expectation insignificant future production volumes or rates carbon dioxide injection and (ii) operating preshigher than reasonably necessary to produce or rates; 

 (e) Class V. Injection wells not included in Class I, II, III, IV or VI. * * * 

Support the proposed language. 

 (f) Class VI. Wells used for geologic 

sequestration of carbon dioxide. 

(f) Class VI. Wells injecting a carbon d

for geologic sequestration except those wells subsection (b)(4) of this section or otherwise ethis Class.
Carbon Sequestration Council (CCS Contact Group) 7 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

Part 146 12. The authority citation for part 146 continues 

to read as follows:  Authority: Safe Drinking Water Act 42, U.S.C. 300f et seq.; Resource Conservation and Recovery Act, 42 U.S.C. 6901 et seq. 

Support the proposed language. 

146.5 13. Section 146.5 is amended as follows: (b) Class II. Classification of Wells: 

 (b) Class II. Wells which inject flui

enhanced recovery of oil or natural gas; (3) Fhydrocarbons.... and 

 (4) For enhanced recovery of oil o

where geologic sequestration is occurring connection with enhanced recovery of oil oprovided (i) there is reasonable expectation 
Carbon Sequestration Council (CCS Contact Group) 8 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

insignificant future production volumes or rates carbon dioxide injection and (ii) operating preshigher than reasonably necessary to produce or rates; 

 a. Revising the first sentence in paragraph (e) introductory text; and  (e) Class V. Injection wells not included in Class I, II, III, IV or VI. * * * 

Support the proposed language. 

 b. Adding paragraph (f). (f) Class VI. Wells used for geologic sequestration of carbon dioxide beneath the lowermost formation containing an underground source of drinking water (USDW). 

 (f) Class VI. Wells injecting a carbon d

for geologic sequestration except those wells subsection (b)(4) of this section or otherwise ethis Class. 
Carbon Sequestration Council (CCS Contact Group) 9 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

Part 146 Subpart H 

14. Subpart H is added to read as follows: Subpart H—Criteria and Standards Applicable to Class VI Wells Sec. 146.82 Required Class VI permit information. 146.83 Minimum criteria for siting. 146.84 Area of review and corrective action. 146.85 Financial responsibility. 146.86 Injection well construction requirements. 146.87 Logging, sampling, and testing prior to injection well operation. 

Support the proposed language. 
Carbon Sequestration Council (CCS Contact Group) 10 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

146.81 Applicability.

 (a) This subpart establishes criteria and standards for underground injection control programs to regulate Class VI carbon dioxide geologic sequestration injection wells. 

These sections may require further revisionconforming language. 

 (b) This subpart applies to wells used to inject carbon dioxide specifically for the purpose of geologic sequestration, i.e., the long-term containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. 

 (b) This subpart applies to wells ucarbon dioxide exclusively for the purpose sequestration, i.e., the long-term containment 

liquid or supercritical carbon dioxide stream 

geologic formations other than oil or gas reseams, basalts, or salt caverns. 

 (c) This subpart applies to owners and operators of permit or rule-authorized Class I industrial, Class II, or Class V experimental carbon dioxide injection projects who seek to apply for a Class VI geologic sequestration permit for their well or wells. If the Director determines that USDWs will not be endangered, such wells are exempt, at the Director’s discretion, from the casing and cementing requirements at §§ 146.86(b) and 146.87(a)(1) through (3). 

 (c) This subpart applies to owners and permit or rule-authorized Class I industrial, Chave ceased and will no longer be used recovery of oil or natural gas, or Class V experidioxide injection projects who seek to apply fgeologic sequestration permit for their well oDirector determines that USDWs will not be such wells are exempt, at the Director’s discrecasing and cementing requirements at §§ 1

146.87(a)(1) through (3). Class VI requirements 

of this Part. Wells constructed in accordance wrequirements of § 146.22 and used in CO2 se
Carbon Sequestration Council (CCS Contact Group) 11 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

have demonstrated MIT are exempt from the re§§146.86 and 146.87.

146.81(d) Definitions (d) Definitions. The following definitions apply to 

this subpart. To the extent that these definitions conflict with those in § 146.3 these definitions govern: 

Area of review means the region surrounding the geologic sequestration project that may be impacted by the injection activity. The area of review is based on computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream. 

 (d) Definitions. The following definitionsubpart. To the extent that these definitions those in § 146.3 these definitions govern: Area of review means the region surrounding 

sequestration project that may be impacted by activity. The area of review is based on modeling that accounts for the physical aproperties of all phases of the injected castream. subsurface three-dimensional extent 

dioxide plume, associated pressure front, as overlying formations and surface area above tregion. 

Carbon dioxide plume means the underground extent, in three dimensions, of an injected carbon dioxide stream. Carbon dioxide stream means carbon dioxide that has been captured from an emission source (e.g., a power plant), plus incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. This subpart does not apply to any carbon dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261. 

Carbon dioxide plume means the undergrouthree dimensions, of an injected carbon dioxide Carbon dioxide stream means carbon dio

physical state or form, and any associated 

derived from the that has been captured from 

source (e.g., a power plant), plus incidentsubstances derived from the source matercapture process, and any or its processing, an

added to enable or improve the injection subpart does not apply to any carbon dioxidmeets the definition of a hazardous waste unde261. 

Confining zone means a geologic formation, group of formations, or part of a formation stratigraphically overlying the injection zone that acts as a barrier to fluid movement. 

Confining zone means a geological formation, gformations, or part of a formation that is capable fluid movement from an injection zone.
Carbon Sequestration Council (CCS Contact Group) 12 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

Corrective action means the use of Director approved methods to assure that wells within the area of review do not serve as conduits for the movement of fluids into underground sources of drinking water (USDW).

Support the proposed language. 

Geologic sequestration means the long-term containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. This term does not apply to its capture or transport. 

Geologic sequestration means the long-term ca gaseous, liquid or supercritical carbon diox

subsurface geologic formations. This term doeits capture or transport. 

Geologic sequestration project means an injection well or wells used to emplace a carbon dioxide stream beneath the lowermost formation containing a USDW. It includes the subsurface three-dimensional extent of the carbon dioxide plume, associated pressure front, and displaced brine, as well as the surface area above that delineated region.

Geologic sequestration project means an injewells used to emplace a carbon dioxide stream 

lowermost formation containing a USDW into 

zone exclusively for the purpose of geologic seqincludes the subsurface three-dimensional ecarbon dioxide plume, associated pressurdisplaced brine, as well as the surface aredelineated region. 

Injection zone means a geologic formation, group of formations, or part of a formation that is of sufficient a real extent, thickness, porosity, and permeability to receive carbon dioxide through a well or wells associated with a geologic sequestration project. . 

Injection zone means a geologic formatioformations, or part of a formation that is of s

extent, thickness, porosity, and permeabilitcarbon dioxide receiving fluids through a associated with a geologic sequestration projec

Post-injection site care means appropriate monitoring and other actions (including corrective action) needed following cessation of injection to assure that USDWs are not endangered as required under § 146.93

Post-injection site care means appropriate m

other actions (including corrective action) nee

cessation of injection to assure that USD

endangered, as required under §146.93.
Carbon Sequestration Council (CCS Contact Group) 13 

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Pressure front means the zone of elevated pressure that is created by the injection of carbon dioxide into the subsurface. For the purposes of this subpart, the pressure front of a carbon dioxide plume refers to a zone where there is a pressure differential sufficient to cause the movement of injected fluids or formation fluids into a USDW. 

Pressure front means the zone of elevated prcreated by the injection of the carbon dioxide s

subsurface, For the purposes of this subpart, 

front of a carbon dioxide plume refers to a zon

is a pressure differential sufficient to cause injected fluids the carbon dioxide stream or fo

from the injection zone into a USDW.

Site closure the point/time, as determined by the Director following the requirements under § 146.93, at which the owner or operator of a GS site is released from postinjection site care responsibilities.

Site closure means the point/time, as deterDirector following the requirements under §146the owner or operator of a GS site project is 

post-injection site care responsibilities. 

Transmissive fault or fracture means a fault or fracture that has sufficient permeability and vertical extent to allow fluids to move between formations. 

Transmissive fault or fracture means a fault ohas sufficient permeability and vertical extent to move between formations beyond the confini

146.82 Required Class VI permit information 

This section sets forth the information which the owner or operator must submit to the Director in order to be permitted as a Class VI well. The application for a permit for construction and operation of a Class VI well must include the following: 

Support the proposed language. 

 (a) Information required in 40 CFR 144.31(e)(1) through (6); 

Support the proposed language. 

146.82(a) (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 

 (b) A surface map showing the propofor the injection well(s) for which a permit is sapplicable area of review. Within the area of remust show the number, or name and location injection wells, producing wells, abandoned wwells or dry holes, deep stratigraphic borehoEPA approved subsurface cleanup sites, surfwater, springs, mines (surface and subsurfawater wells and other pertinent surface featustructures intended for human occupancy an

map should also show faults, if known or sus
Carbon Sequestration Council (CCS Contact Group) 14 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

record is required to be included on this map; information of public record is required to be in

map; 

 (c) The area of review based on modeling, using data obtained during logging and testing of the well and the formation as required by paragraphs (l), (r), and (s) of this section; 

 (c) A map delineating the area of rev

upon modeling, using all available data in

obtained during logging and testing of the 

formation as required by paragraphs (l), (r), asection any wells in the area of review

 (d) Information on the geologic structure and hydrogeologic properties of the proposed storage site and overlying formations, including:  (1) Maps and cross sections of the area of review;  (2) Location, orientation, and properties of known or suspected faults and fractures that may transect the confining zone(s) in the area of review and a determination that they would not interfere with containment; 

 (d) Known information on the geologic 

hydrogeologic reservoir properties of the prop

site and overlying formations, including:  (1) Isopach maps and of the proposed 

confining zone(s), a structural contour map huof the proposed injection zone, and at least cross sections of the area of review showing formations from the surface to total depth.  (2) Location, orientation, and propertiesuspected subsurface faults and fractures that 

the confining zone(s) in the area of redetermination that they would not interfere with 

 (3) Information on seismic history including the presence and depth of seismic sources and a determination that the seismicity would not interfere with containment;  (4) Data on the depth, areal extent, thickness, mineralogy, porosity, permeability and capillary pressure of 

the injection and confining zone(s); including geology/facies changes based on field data which may include geologic cores, outcrop data, seismic surveys, well logs, and names and lithologic descriptions;  (5) Geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid pressures within the confining zone; and 

 (3) Information on seismic history that the proposed area of review, including knowledseismic events, including the presence and desources and a determination that the seismicinterfere with containment;  (4) Data sufficient to demonstrate the of the injection and confining zone(s), includindepth, areal extent, thickness, mineralogy, popermeability reservoir pressure and of the confining zone(s) within the area of reviegeologic changes based on field data which geologic cores, outcrop data, seismic surveycapillary pressure tests and names adescriptions;  (5) Known geomechanical information o

stress, ductility, rock strength, and in situ fluid pwithin the confining zone(s) within the area of re
Carbon Sequestration Council (CCS Contact Group) 15 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

 (6) Geologic and topographic maps and cross sections illustrating regional geology, hydrogeology, and the geologic structure of the local area. 

Delete item 6 because this issue is covered sections such as (b). 

146.82(e) (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; 

 (e) A tabulation record of all we

penetrations within the area of review which 

reach the injection or confining zone(s). Savailable in the public record must include a each well’s penetration’s type, construction, 

location, depth, record of plugging and/ or coany additional information the Director may requ

 (f) Maps and stratigraphic cross sections indicating the general vertical and lateral limits of all USDWs, water wells and springs within the area of review, their positions relative to the injection zone(s) and the direction of water movement, where known; 

 (f) Maps and stratigraphic cross secti

the general vertical and lateral limits of all Uwells and springs within the area of review, trelative to the injection zone(s) and the direcmovement, where known; Potentiometric 

surface map(s) of existing aquifers being utilizor public water supplies and the direction of groin these aquifers within the area of review. geologic cross sections showing the thickness vertical and lateral limits of all USDWs withireview.

 (g) Baseline geochemical data on subsurface formations, including all USDWs in the area of review; 

 (g) Baseline geochemical data on subs

formations, including all USDWs in the area of r

Compilation of available geochemical data on thinjection zone and nearest porous and permeababove the confining zone.

 (h) Proposed operating data:  (1) Average and maximum daily rate and volume of the carbon dioxide stream;  (2) Average and maximum injection pressure;  (3) The source of the carbon dioxide stream; and  (4) An analysis of the chemical and physical characteristics of the carbon dioxide stream; 

 (h) Proposed operating data:  (1) Average and maximum daily injecvolume of the carbon dioxide stream;  (2) Average and maximum surfa

pressure;  (3) The source of the carbon dioxide str (4) An analysis of the chemical characteristics of the carbon dioxide stream; Clarifications 
Carbon Sequestratio un n Co cil (CCS Contact Group) 16 

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146.82 (i) The compatibility of the carbon dioxide stream 

with fluids in the injection zone and minerals in both the injection and the confining zone(s), based on the results of the formation testing program, and with the materials used to construct the well; 

Support the proposed language. 

146.82 (j) Proposed formation testing program to obtain an 

analysis of the chemical and physical characteristics of the injection zone and confining zone; 

Support the proposed language. 

146.82 (k) Proposed stimulation program and a 

determination that stimulation will not interfere with containment; 

 (k) Proposed stimulation progradetermination that stimulation will not containment; 

146.82 (l) The results of the formation testing program as 

required in paragraph (j) of this section;  (m) Proposed procedure to outline steps necessary 

to conduct injection operation;  (n) Schematic or other appropriate drawings of the surface and subsurface construction details of the well;  (o) Injection well construction procedures that meet the requirements of § 146.86; 

 (l) The results of the formation testinrequired in paragraph (j) of this section; (m) Proposed procedure to outline steps conduct injection operation;  (n) A wellbore schematic or other appro

drawings of the surface and of the subsurface c

details of the well and surface wellhead constru

 (o) Injection well construction proceduthe requirements of § 146.86; 

 (p) Proposed area of review and corrective action plan that meets the requirements under § 146.84; 

Support the proposed language. 

 (q) The status of corrective action on wells in the area of review;  (r) All available logging and testing program data on the well required by § 146.87;  (s) A demonstration of mechanical integrity 

 (q) The Any status of corrective actio

the area of review;  (r) All available logging and testing prothe well required by § 146.87;  (s) The proposed demonstration 
Carbon Sequestration Council (CCS Contact Group) 17 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

pursuant to § 146.89;  (t) A demonstration, satisfactory to the Director, that the applicant has met the financial responsibility requirements under § 146.85; 

mechanical integrity pursuant to  (t) A demonstration, satisfactory to the Dthe applicant has met the financial responsibility requirements under § 146.85; 

146.82(u) (u) Proposed testing and monitoring plan required 

by § 146.90;  (v) Proposed injection well plugging plan required by § 146.92(b);  (w) Proposed post-injection site care and site closure plan required by § 146.93(a);  (x) Proposed emergency and remedial response plan required by § 146.94; and  (y) Any other information requested by the Director.

 (u) Proposed testing and monitoring pla§ 146.90;  (v) Proposed injection and monitoring wplugging plan required by § 146.92(b);  (w) Proposed post-injection site care anplan required by § 146.93(a);  (x) Proposed emergency and remedial plan required by § 146.94; and  (y) Any other information requested by 

146.83 3. Minimum criteria for siting 

 (a) Owners or operators of Class VI wells must demonstrate to the satisfaction of the Director that the wells will be sited in areas with a suitable geologic system. The geologic system must be comprised of:  (1) An injection zone of sufficient areal extent, thickness, porosity, and permeability to receive the total anticipated volume of the carbon dioxide stream; 

Support the proposed language. 

 (2) A confining zone(s) that is free of transmissive faults or fractures and of sufficient areal extent and integrity 

to contain the injected carbon dioxide stream and displaced 

formation fluids and allow injection at proposed maximum pressures and volumes without initiating or propagating fractures in the confining zone(s); and 

 (2) A confining zone(s) that is lateraand free of known transecting, transmiss

fractures and of sufficient areal extent and integ

the injected carbon dioxide stream and displafluids and allow injection at proposed maximand volumes without initiating or propagating frconfining zone(s); and over an area sufficient 

movement of injected or displaced fluids into a 
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Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

 (b) At the Director’s discretion, owners or operators of Class VI wells must identify and characterize additionalzones that will impede vertical fluid movement, are free of faults and fractures that may interfere with containment, allow for pressure dissipation, and provide additional opportunities for monitoring, mitigation and remediation. 

 (b) At the Director’s discretion, owners 

of Class VI wells must identify and characterzones that will impede vertical fluid movemenfaults and fractures that may interfere with allow for pressure dissipation, and proviopportunities for monitoring, mitigation and rem

146.84 146.84. Area of review and corrective action 

 (a) The area of review is the region surrounding the geologic sequestration project that may be impacted by the injection activity. The area of review is based on computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream. 

 (a) The area of review is the region su

geologic sequestration project that may be iminjection activity. The area of review computational modeling that accounts for the chemical properties of all phases of the injdioxide stream. the subsurface three-dimensio

the carbon dioxide plume, associated pressure as the overlying formations and surface aredelineated region.

 (b) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan to delineate the area of review for a proposed geologic sequestration project, periodically reevaluate the delineation, and perform corrective action that meets the requirements of this section and is acceptable to the Director. As a part of the permit application for approval by the Director, the owner or operator must submit an area of review and correctiveaction plan that includes the following information:  (1) The method for delineating the area of review that meets the requirements of paragraph (c) of this section, including the model to be used, assumptions that will be made, and the site characterization data on which the model will be based; 

 (b) The owner or operator of a Class prepare, maintain, and comply with a plan to area of review for a proposed geologic sequestperiodically reevaluate the delineation, 

corrective action that meets the requirements and is in a manner and at a frequency acce

Director. As a part of the permit application, fo

the Director the owner or operator must subm

review and corrective action plan that includes information:  (1) The method for delineating the athat meets the requirements of paragraph (c) oincluding the model to be used, assumptionmade, and the site characterization data on whwill be based; 

146.84(b)(2) (2) A description of: 

 (i) The minimum fixed frequency, not to exceed 10 years, the owner or operator proposes to reevaluate the area of review;  (ii) The monitoring and operational conditions that would warrant a reevaluation of the area of review prior to the next scheduled reevaluation as determined by the minimum fixed frequency established in paragraph (b)(2)(i) 

 (2) A description of: (i) The minimum fixed frequency, not to exceed 

owner or operator proposes to reevaluate the a

(ii) The monitoring and operational c

would warrant a reevaluation of the area of rthe next scheduled reevaluation as determminimum fixed frequency established in paragrathis section.
Carbon Sequestration Council (CCS Contact Group) 19 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

of this section. 

 (iii) How monitoring and operational data (e.g., injection rate and pressure) will be used to inform an area 

of review reevaluation; and 

 (iii)(i) How monitoring and operation

injection rate and pressure) will be used to inforeview reevaluation; and 

 (iv) How corrective action will be conducted to meet the requirements of paragraph (d) of this section, including what corrective action will be performed prior to injection and what, if any, portions of the area of review will have corrective action addressed on a phased basis and how the phasing will be determined; how corrective action will be adjusted if there are changes in the area of review; and how site access will be guaranteed for future corrective action. 

 (iv ii) How corrective action will be 

meet the requirements of paragraph (d) of including what corrective action will be perfoinjection and what, if any, portions of the area have corrective action addressed on a phased bthe phasing will be determined; how corrective adjusted if there are changes in the area of revsite access will be guaranteed arranged for fut

action. 

146.84(c) (c) Owners or operators of Class VI wells must 

perform the following actions to delineate the area of review, identify all wells that require corrective action, and perform corrective action on those wells:  (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. The model must: 

 (c) Owners or operators of Class Vperform the following actions to delineate the aidentify all wells that require corrective actioncorrective action on those wells:  (1) Predict, using computational mprojected lateral and vertical migration of the cplume and formation fluids in the subsurfacommencement of injection activities until injeplume movement ceases, pressure differentiacause the movement of injected fluids or formaa USDW are no longer present, or after for 

period as determined by the Director. The mo

must: 
Carbon Sequestration Council (CCS Contact Group) 20 

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146.84(c)(i) (i) Be based on detailed geologic data collected to 

characterize the injection zone, confining zone and any additional zones; and anticipated operating data, including injection pressures, rates and total volumes over the proposed life of the geological sequestration project;  (ii) Take into account any geologic heterogeneities, data quality, and their possible impact on model predictions; and 

 (i) Be based on detailed geologic d

available to characterize the injection zone, cand any additional zones; and anticipated op

including injection pressures, rates and total the proposed life of the geological sequestrati

duration of injection;  (ii) Take into account any relev

heterogeneities, and data quality, and their poon model predictions; and 

 (iii) Consider potential migration through faults, fractures, and artificial penetrations. 

Support the proposed language. 

 (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 

 (2) Using methods approved by the Di

all known artificial penetrations into the coavailable in the public record, including abandoned wells and underground mines, in review that may penetrate reach the confining 

a description of each well’s type, constructionlocation, depth, record of plugging and/or coany additional information the Director may requ

 (3) Determine which abandoned wells in the area of review have been plugged (as required by § 146.92) in a manner that prevents the movement of carbon dioxide or 

associated fluids that may endanger USDWs. 

 (3) Determine which abandoned wpursuant to 146.84 (c) (2) in the area of revie

plugged (as required by §146.92) in a manner the movement of carbon dioxide or associa

fluids that may endanger USDWs. 

146.84(d) (d) Owners or operators of Class VI wells must 

perform corrective action on all wells in the area of review that are determined to need corrective action using methods necessary to prevent the movement of fluid into or between USDWs including use of corrosion resistant materials, where appropriate. 

 (d) Owners or operators of Class Vperform corrective action using materials suitabthe carbon dioxide stream and formation fluidin the area of review identified in 146.84(c

determined to need corrective action”. us

necessary to prevent the movement of fluid inUSDWs including use of corrosion resistant maappropriate.
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 (e) If monitoring data indicate an endangerment to USDWs, the owner or operator must notify the Director and cease operations as required by § 146.94. 

 (e) If monitoring data indicate an end

USDWs, the owner or operator must notify the cease operations as required by § 146.94.

 (f) At the minimum fixed frequency, not to exceed 10 years, as specified in the area of review and corrective action plan, or when monitoring and operational conditions warrant, owners or operators must:  (1) Reevaluate the area of review in the same manner specified in paragraph (c)(1) of this section;  (2) Identify all wells in the reevaluated area of review that require corrective action in the same manner specified in paragraph (c)(2) of this section; 

 (f) At the minimum fixed frequency, no

years, as specified in the approved area ocorrective action plan, or When monitoring an

conditions warrant, owners or operators must:  (1) Reevaluate the area of review manner specified in paragraph (c)(1) of this sec (2) Identify all wells in the reevaluated athat require corrective action in the same mannparagraph (c)(2) of this section; 

 (3) Perform corrective action on wells requiring corrective action in the reevaluated area of review in the same manner specified in paragraph (c)(3) of this section; and  (4) Submit an amended area of review and corrective action plan or demonstrate to the Director through monitoring data and modeling results that no amendment to the area of review and corrective action plan is needed. 

 (3) Perform corrective action on wcorrective action in the reevaluated area of same manner specified in paragraph (c)(3) oand  (4) Submit an amended area of corrective action plan or demonstrate to the Dimonitoring data and modeling results that no 

change to the area of review and corrective needed. 

146.84(g) (g) The emergency and remedial response plan (as 

required by § 146.94) and a demonstration of financial responsibility (as described by § 146.85) must account for the entire area of review, regardless of whether or not corrective action in the area of review is phased. 

 (g) The emergency and remedial resprequired by § 146.94) and a demonstration responsibility (as described by § 146.85) musthe entire area of review as modified pursuant 

regardless of whether or not corrective action review is phased. 

146.85 146.85 Financial responsibility 

 (a) The owner or operator must demonstrate and maintain financial responsibility and resources for corrective action (that meets the requirements of § 146.84), injection well plugging (that meets the requirements of § 146.92), post-injection site care and site closure (that meets the 

 (a) The owner or operator must demmaintain financial responsibility and resources action (that meets the requirements of § 146well plugging (that meets the requirements post-injection site care and site closure (th
Carbon Sequestration Council (CCS Contact Group) 22 

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requirements of § 146.93), and emergency and remedial response (that meets the requirements of§ 146.94) in a manner prescribed by the Director until:  (1) The Director receives and approves the completed post-injection site care and site closure plan; and (2) The Director determines that the site has reached the end of the post-injection site care period. 

requirements of § 146.93), and emergency response (that meets the requir§ 146.94) in a manner prescribed by the Directo (1) The Director receives well pluidentified in 146.92(d) and approves or com

completed post-injection site care and site clo

appropriate; and  (2) The Director determines that the site the end of the post-injection site care period. 

 (b) The owner or operator must provide to the Director, at a frequency determined by the Director, written updates of adjustments to the cost estimate to account for any amendments to the area of review and corrective action plan (§ 146.84), the injection well plugging plan (§ 146.92), and the post-injection site care and site closure plan (§ 146.93). 

 (b) The owner or operator must pDirector, at a frequency determined by the Dimore frequently than annually, written adjustments to the cost estimate to accoamendments change to the area of review a

action plan (§146.84), the injection well p(§146.92), and the post-injection site care anplan (§146.93). 

146.85(c) (c) The owner or operator must notify the Director 

of adverse financial conditions such as bankruptcy, that may affect the ability to carry out injection well plugging and post-injection site care and site closure. 

 (c) The owner or operator must notify tadverse financial conditions such as bankrup

affect the ability to carry out injection well plugginjection site care and site closure. 

 (d) The operator must provide an adjustment of the cost estimate to the Director if the Director has reason to 

believe that the original demonstration is no longer adequate to cover the cost of injection well plugging (as required by § 146.92) and post-injection site care and site closure (as required by § 146.93). 

 (d) The operator must provide an adjucost estimate to the Director if the Director hbelieve that original the most recent demon

longer adequate to cover the cost of injection (as required by §146.92) and post-injection site closure (as required by §146.93) 

146.86 6. Injection well construction requirements 

 (a) General. The owner or operator must ensure that all Class VI wells are constructed and completed to:  (1) Prevent the movement of fluids into or between USDWs or into any unauthorized zones;  (2) Permit the use of appropriate testing devices and workover tools; and 

6. Injection well construction requirements  (a) General. The owner or operator muall Class VI wells are constructed and complete (1) Prevent the movement of fluid int

USDWs or into any unauthorized zones; c

contaminant into USDWs, if the presence of thamay cause a violation of any primary dregulation under 40 CFR part 142 or m
Carbon Sequestration Council (CCS Contact Group) 23 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

 (3) Permit continuous monitoring of the annulus space between the injection tubing and long string casing. 

adversely affect the health of persons;  (2) Permit the use of appropriate testinworkover tools; and  (3) Permit continuous monitoring of space between the injection tubing and long str

 (b) Casing and Cementing of Class VI Wells.  (1) Casing and cement or other materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the life of the 

geologic sequestration project. All well materials must be compatible with fluids with which the materials may be expected to come into contact and meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. The casing and cementing program must be designed to prevent the movement of fluids into or between USDWs. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information: 

 (b) Casing and Cementing of Class VI W (1) Casing and cement or other matthe construction of each Class VI well must hstructural strength and be designed for the op

the geologic sequestration project well. All w

must be compatible suitable for use with the flu

the materials may be expected to come into meet or exceed test standards or practices such materials by the American Petroleum InInternational, or comparable standards acceDirector. The casing and cementing progrdesigned to prevent the movement of fluids inUSDWs. In order to allow the Director to dspecify casing and cementing requirements, operator must provide the following information

146.86(b)(1) (i) Depth to the injection zone; 

 (ii) Injection pressure, external pressure, internal pressure and axial loading;  (iii) Hole size;  (iv) Size and grade of all casing strings (wall thickness, external diameter, nominal weight, length, joint specification and construction material);  (v) Corrosiveness of the carbon dioxide stream, and formation fluids;  (vi) Down-hole temperatures;  (vii) Lithology of injection and confining zones; 

 (i) Depth to the injection zone;  (ii) Injection pressure, external prespressure and axial loading;  (iii) Hole size;  (iv) Size and grade of all casing thickness, external diameter, nominal weightspecification and construction material);  (v) Corrosiveness Composition of the cstream and formation fluids; (vi) Down-hole and pressures;  (vii) Lithology of injection and confining 
Carbon Sequestration Council (CCS Contact Group) 24 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

 (viii) Type or grade of cement; and  (ix) Quantity, chemical composition, and temperature of the carbon dioxide stream. 

 (viii) Type or grade of cement and addi (ix) Quantity, chemical composition, anof the carbon dioxide stream. 

 (2) Surface casing must extend through the base of the lowermost USDW and be cemented to the surface. 

 (2) Surface casing must extend througthe lowermost USDW above the injection cemented to the surface except that the approve a combination of cemented surface cemented long string casing to achieve continfrom the surface through the base of the loweabove the injection zone.

 (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface 

in one or more stages. 

 (3) At least one long string casing, usi

number of centralizers set in a manner so a

cement bond through the injection and confining 

long string casing must extend to the injection zbe cemented isolated by circulating cement to 

one or more stages. placing cement and/or otechnologies as necessary to provide adequathe injection zone and provide for protection of U

146.86(b) (4) Circulation of cement may be accomplished by 

staging. The Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the cement does not allow fluid movement behind the well bore. 

 (4) Circulation of cement may be acc

staging. The Director may approve an alternatcementing in cases where the cement cannot bto the surface, provided the owner or demonstrate by using logs that the cement dfluid movement behind the well bore.

 (5) Cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the geologic sequestration project. The integrity and location of the cement shall be verified using technology capable of evaluating cement 

 (5) Cement and cement additivecompatible suitable for use with the carbon d

and formation fluids and of sufficient quality amaintain integrity over the design operatin

geologic sequestration project well. The integrit

of the cement shall be verified using technolo
Carbon Sequestration Council (CCS Contact Group) 25 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

quality radially and identifying the location of channels to ensure that USDWs are not endangered. 

evaluating cement quality radially and identifyinof channels to ensure that USDWs are not enda

146.86(c) (c) Tubing and packer. 

 (1) All owner and operators of Class VI wells must inject fluids through tubing with a packer set at a depth opposite a cemented interval at the location approved by the Director.  (2) In order for the Director to determine and specify requirements for tubing and packer, the owner or operator must submit the following information:  (i) Depth of setting;  (ii) Characteristics of the carbon dioxide stream (chemical content, corrosiveness, temperature, and density); 

 (c) Tubing and packer.  (1) All owner and operators of Class inject fluids through tubing with a packer seopposite a cemented interval at the location apDirector.  (2) In order for the Director to determinrequirements for tubing and packer, the ownemust submit the following information:  (i) Depth of setting;  (ii) Composition of the carbon dio

(chemical content, corrosiveness, temperature, 

146.86(c)(2) (iii) Injection pressure; 

 (iv) Annular pressure;  (v) Injection rate (intermittent or continuous) and volume of the carbon dioxide stream;  (vi) Size of casing; and  (vii) Tubing tensile, burst, and collapse strengths. 

 (iii) Maximum proposed Injection tem

pressure;  (iv (v

) Maximum proposed Annular pressu

) Maximum proposed Injection rate (

continuous) and volume of the carbon dioxide s

146.87 7. Logging, sampling, and testing prior to injection well 

operation  (a) During the drilling and construction of a Class VI 

injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic formations to assure conformance with the injection well construction requirements under § 146.86, and to establish accurate baseline data against which future measurements 

 (a) During the drilling and construction injection well, the owner or operator must rulogs, surveys and tests to determine or verthickness, porosity, permeability, and lithologsalinity of any formation fluids in, all relevformations to assure evaluate conformance wit

well construction requirements under §146establish accurate baseline data against measurements may be compared. The ownemust submit to the Director a descriptive repora knowledgeable log analyst that includes an in
Carbon Sequestration Council (CCS Contact Group) 26 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, such logs and tests must include: 

the results of such logs and tests. At a minim

and tests must include: The Director may requ

and tests as may be needed after taking into availability of similar data in the area of the dconstruction plan, and the need for additional inmay arise from time to time as the constructiprogresses and these may include the following

 (1) Deviation checks during drilling on all holes constructed by drilling a pilot hole which are enlarged by reaming or another method. Such checks must be at sufficiently frequent intervals to determine the location of the borehole and to assure that vertical avenues for fluid movement in the form of diverging holes are not created during drilling; and 

Support the proposed language. 

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

Support the proposed language. 

(i) Resistivity, spontaneous potential, and caliper 

logs before the casing is installed; and 

 (i) Resistivity, spontaneous potentiallogs before the casing is installed; and 

 (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented. 

 (ii) A Cement bond and variable dens

temperature log evaluation log(s) after the cas

cemented. 

146.87(a) (3) Before and upon installation of the long string 

casing: . 

Support the proposed language. 
Carbon Sequestration Council (CCS Contact Group) 27 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

(i) Resistivity, spontaneous potential, porosity, 

caliper, gamma ray, fracture finder logs, and any other logs the Director requires for the given geology before the casing is installed; and 

 (i) Resistivity, spontaneous potentcaliper, gamma ray, fracture finder logs and a

the Director requires based on site specific crisk-based factors for the given geology before installed; and 

 (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented 

 (ii) A Cement bond and variable dens

temperature log evaluation log(s) after the cas

cemented. 

146.87(a)(4) (4) A series of tests designed to demonstrate the 

internal and external mechanical integrity of injection wells, which may include:  (i) A pressure test with liquid or gas;  (ii) A tracer survey such as oxygen-activation logging;  (iii) A temperature or noise log;  (iv) A casing inspection log, if required by the Director; and 

 (4) A series of tests Test(s) 

demonstrate the internal and external mechaniinjection wells, which may include:  (i) A pressure test with liquid or gas;  (ii) A tracer survey Diagnostic tools su

activation logging;  (iii) A temperature or noise log; and/or

 (iv) A casing inspection log. if req

Director; and

 (5) Any alternative methods that provide equivalent or better information and that are required of and/or approved of by the Director. 

 (5) Any alternative methods that provor better information and that are require

approved of by the Director. 

146.87(b) (b) The owner or operator must take and submit to 

the Director whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core other formations in the borehole. 

 (b) The owner or operator must sDirector a report describing whole cores or srepresentative of the injection zone and confininformation fluid samples from the injection Director may accept data from cores and fluid 

nearby wells if the owner or operator can demcore retrieval is not possible and that such c

representative of conditions at the well in the 

Director may require the owner or operator 
Carbon Sequestration Council (CCS Contact Group) 28 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

formations in the borehole.

 (c) The owner or operator must record the fluid temperature, pH, conductivity, reservoir pressure and the 

static fluid level of the injection zone(s). 

 (c) Prior to injection well operation, operator must record provide representative i

the fluid formation temperature, formation 

conductivity, and reservoir pressure and the st

of the injection zone(s). 

 (d) At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zone(s):  (1) Fracture pressure;  (2) Other physical and chemical characteristics of the injection and confining zones; and  (3) Physical and chemical characteristics of the formation fluids in the injection zone. 

(d) At a minimum, the owner or o

determine or calculate the following informatiothe injection and confining zone(s):

(1) Fracture pressure;(2) Other physical and chemical charac

injection and confining zones; and

(3) Physical and chemical characte

formation fluids in the injection zone.

 (e) Upon completion, but prior to operation, the owner or operator must conduct the following tests to verify hydrogeologic characteristics of the injection zone:  (1) A pump test; or  (2) Injectivity tests. 

 (e) (d) Upon completion but Prior to 

operation, the owner or operator mustconduct the following tests to verify 

characteristics of the injection zone:

(1) A pump test; or(2) Injectivity tests.

estimate fracture pressures of the injection zones and injectivity of the injection zone. Est

be based on representative hydrogegeomechanical characteristics of the injection z

146.87(f) (f) The owner or operator must provide the Director 

with the opportunity to witness all logging and testing by this 

subpart. The owner or operator must submit a schedule of such activities to the Director 30 days prior to conducting the first test and submit any changes to the schedule 30 days prior to the next scheduled test. 

 (e) The owner or operator must providwith the opportunity to witness all logging and subpart. The owner or operator must submit such activities to the Director upon spudding submit any changes to the schedule 48 hourscheduled test. 
Carbon Sequestration Council (CCS Contact Group) 29 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

146.88 8. Injection well operating requirements 

 (a) Except during stimulation, the owner or operator must ensure that injection pressure does not exceed 90 percent of the fracture pressure of the injection zone so as to assure that the injection does not initiate new fractures or 

propagate existing fractures in the injection zone. In no case may injection pressure initiate fractures in the confining zone(s) or cause the movement of injection or formation fluids that endangers a USDW. 

 (a) The owner or operator must comaximum injection pressure limit approved by and specified in the permit. In approving a maxipressure limit, the Director shall consider the tests and, where appropriate, geomechanical othat assess the risks of tensile failure and sheDirector shall approve limits that, with a reasonacertainty, will avoid initiation or propagation of fconfining zone or cause otherwise non-transtransecting the confining zone to become transcase may injection pressure cause movement formation fluids in a manner prohibited by 144.12(a).

 (b) Injection between the outer-most casing protecting USDWs and the well bore is prohibited. 

 (b) Injection of the CO2 stream outermost casing protecting USDWs and the prohibited. 

 (c) The owner or operator must fill the annulus between the tubing and the long string casing with a noncorrosive fluid approved by the Director. The owner or 

operator must maintain on the annulus a pressure that exceeds the operating injection pressure, unless the Director determines that such requirement might harm the 

integrity of the well. 

 (c) The owner or operator must fill between the tubing and the long string casincorrosive fluid approved by the Director. Toperator must maintain a positive pressure on t
Carbon Sequestration Council (CCS Contact Group) 30 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

146.88(d) (d) Other than during periods of well workover 

(maintenance) approved by the Director in which the sealed tubing-casing annulus is of necessity disassembled for maintenance or corrective procedures, the owner or operator must maintain mechanical integrity of the injection well at all times. 

Support the proposed language.. 

 (e) The owner or operator must install and use continuous recording devices to monitor: The injection pressure; the rate, volume, and temperature of the carbon 

dioxide stream; and the pressure on the annulus between the tubing and the long string casing and annulus fluid volume; and must install and use alarms and automatic down-hole shut-off systems, designed to alert the operator and shut-in the well when operating parameters such as annulus pressure, injection rate or other parameters approved by the Director diverge beyond permitted ranges 

and/or gradients specified in the permit; 

 (e) The owner or operator must incontinuous recording devices to monitor: pressure; the rate, volume, and temperature dioxide stream and. The owner or operator m

monitor the pressure on the annulus between tthe long string casing and annulus fluid volum

owner or operator must install and use alarms down-hole shut-off systems, designed to alert 

and shut-in the well when operating parameinjection rate, injection pressure, or otheapproved by the Director diverge beyond rgradients specified in the permit; 

 (f) If a down-hole automatic shutdown is triggered or a loss of mechanical integrity is discovered, the owner or operator must immediately investigate and identify as expeditiously as possible the cause of the shutoff. If, upon 

such investigation, the well appears to be lacking mechanical integrity, or if monitoring required under paragraph (e) of this section otherwise indicates that the well may be lacking mechanical integrity, the owner or operator must: 

 (f) If an down-hole automatic shutdow

or a loss of mechanical integrity is discoveredoperator must immediately investigate and expeditiously as possible the cause of the sh

such investigation, the well appears to be lackinintegrity, or if monitoring required under paragrsection otherwise indicates that the well mamechanical integrity, the owner or operator mus
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146.88(f) (1) Immediately cease injection; 

 (2) Take all steps reasonably necessary to determine whether there may have been a release of the injected carbon dioxide stream into any unauthorized zone;

 (3) Notify the Director within 24 hours;  (4) Restore and demonstrate mechanical integrity to the satisfaction of the Director prior to resuming injection; and  (5) Notify the Director when injection can be expected to resume. 

 (1) Immediately cease injection;  (2) Take all steps reasonably ndetermine whether there may have been a rinjected carbon dioxide stream into any unautho (3) Notify the Director within 24 hours o (4) Restore and demonstrate mechanithe satisfaction of the Director prior to resumand  (5) Notify the Director when injecexpected to resume. 

146.89 9. Mechanical integrity 

 (a) A Class VI well has mechanical integrity if:  (1) There is no significant leak in the casing, tubing or packer; and  (2) There is no significant fluid movement into a USDW through channels adjacent to the injection well bore.

Support the proposed language. 

 (b) To evaluate the absence of significant leaks under paragraph (a)(1) of this section, owners or operators must, following an initial annulus pressure test, continuously monitor injection pressure, rate, injected volumes, and pressure on the annulus between tubing and long stem casing and annulus fluid volume as specified in § 146.88(e);

 (b) To evaluate the absence of sigunder paragraph (a)(1) of this section, owners must, following an initial annulus pressure testmonitor and record at least daily, annulus volumes of fluid added to or removed fro

pressure, rate, injected volumes, and pres

annulus between the tubing and long stem stri

annulus fluid volume as specified in §146.88 (e)
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Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

146.89(c) (c) At least once per year, the owner or operator 

must use one of the following methods to determine the absence of significant fluid movement under paragraph (a)(2) of this section:  (1) A tracer survey such as oxygen-activation logging;  (2) A temperature or noise log; or  (3) A casing inspection log, if required by the Director. 

 (c) At least once per year, the ownemust confirm the absence of significant fluunder paragraph (a)(2) of this section usinacceptable to the Director (e.g. including diagnsuch as oxygen-activation logging or temperalogs). 

 (1) A tracer survey such as oxy

logging;

 (2) A temperature or noise log; or

 (3) A casing inspection log, if req

Director.

 (d) The Director may require any other test to evaluate mechanical integrity under paragraph (a)(1) or (a)(2) of this section. Also, the Director may allow the use of a test to demonstrate mechanical integrity other than those listed above with the written approval of the 

Administrator. To obtain approval, the Director must submit 

a written request to the Administrator, which must set forth the proposed test and all technical data supporting its use. The Administrator must approve the request if it will reliably demonstrate the mechanical integrity of wells for which its use is proposed. Any alternate method approved by the Administrator will be published in the Federal Register and may be used in all States in accordance with applicable State law unless its use is restricted at the time of approval by the Administrator. 

Support the proposed language. 

146.89(e) (e) In conducting and evaluating the tests 

enumerated in this section or others to be allowed by the Director, the owner or operator and the Director must apply methods and standards generally accepted in the industry. 

When the owner or operator reports the results of mechanical integrity tests to the Director, he/she shall include a description of the test(s) and the method(s) used. In making his/her evaluation, the Director must review monitoring and other test data submitted since the previous evaluation. 

Support the proposed language. 
Carbon Sequestration Council (CCS Contact Group) 33 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

 (f) The Director may require additional or alternative tests if the results presented by the owner or operator under paragraph (d) of this section are not satisfactory to the Director to demonstrate that there is no significant leak in the casing, tubing or packer or significant movement of fluid into or between USDWs resulting from the injection activity as stated in paragraphs (a)(1) and (2) of this section. 

Support the proposed language. 

146.90 10. Testing and monitoring requirements 

The owner or operator of a Class VI well must prepare, maintain, and comply with a testing and monitoring plan to verify that the geologic sequestration project is operating as permitted and is not endangering USDWs. The testing and monitoring plan must be submitted with the permit application, for Director approval, and must include a description of how the owner or operator will meet the 

requirements of this section. Testing and monitoring associated with geologic sequestration projects must, at a 

minimum, include: 

 (a) Based on a site-specific asses

potential for fluid movement from the injeinjection zone, and on the potential value of moto detect such movement, the owner or opera

VI well must prepare, maintain, and comply and monitoring plan to verify that the geologic 

project is operating as permitted and is not USDWs. The testing and monitoring plan must 

with the permit application, for Director approva description of how the owner or operator requirements of this section; 

146.90 (a) Analysis of the carbon dioxide stream with 

sufficient frequency to yield data representative of its chemical and physical characteristics;  (b) Installation and use, except during well workovers as defined in § 146.86(d), of continuous recording devices to monitor injection pressure, rate and volume; the pressure on the annulus between the tubing and the long string casing; and the annulus fluid volume; 

 (b) The testing and monitoring plan 

minimum, include: 

 (1) analysis of the carbon dioxide 

sufficient frequency to yield data represenchemical and physical characteristics;

 (2) Installation and use, except 

workovers as defined in section 146.88(d), monitoring devices (including digital devicperiodic data) to monitor injection pressure, rate and record at least daily the pressure on between the tubing and the long strong casing; 

 (3) a demonstration of external mecha

pursuant to §146.89(c) until the well is plugged; 

 (4) monitoring of the pressure bu

injection zone annually, including at a minimum
Carbon Sequestration Council (CCS Contact Group) 34 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

of the well for a time sufficient to conduct a valof the pressure fall-off curve at least once eveand 

 (5) a quality assurance plan for al

monitoring requirements. 

146.90 (c) Corrosion monitoring of the well materials for 

loss of mass, thickness, cracking, pitting and other signs of corrosion must be performed on a quarterly basis to ensure that the well components meet the minimum standards for material strength and performance set forth in § 146.86(b) by:  (1) Placing coupons of the well construction materials in contact with the carbon dioxide stream; or  (2) Routing the carbon dioxide stream through a loop constructed with the material used in the well; or  (3) Using an alternative method approved by the Director; 

 (c) Where appropriate, the testing a

plan shall also include: 

 (1) Continuous monitoring for pressu

an appropriately porous and permeable formatthe confining zone.; 

 (2) The use of indirect, geophysical 

determine the position of the CO2 stream froquality in a designated formation, or to provspecific data; 

 (3) Periodic monitoring of water q

appropriately porous and permeable formation injection zone; 

 (4) Periodic monitoring of water qua

more USDWs; 

 (5) Corrosion monitoring of the well 

loss of mass, thickness, cracking, pitting and corrosion performed and recorded at least qumay be modified to be less frequent as appDirector based on construction materiaconditions, and monitoring history to ensure components meet the minimum standards strength and performance set forth in §146.86(b
Carbon Sequestration Council (CCS Contact Group) 35 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

 (i) Analyzing coupons of the well 

materials placed in contact with the carbon diox

 (ii) Routing the carbon dioxide strea

loop constructed with the material used in inspecting the materials in the loop; or 

 (iii) Using an alternative method, mat

period approved by the Director; 

 (6) Any additional testing and monitori

to support modeling the extent of the carbon and the position of the pressure front; and 

 (7) Any additional testing and monitor

to determine whether fluid movement is occubetween USDWs that would endanger a USDW

146.90(d) (d) Periodic monitoring of the ground water quality 

and geochemical changes above the confining zone(s) that may be a result of carbon dioxide movement through the confining zone or additional identified zones:  (1) The location and number of monitoring wells must be based on specific information about the geologic sequestration project, including injection rate and volume, geology, the presence of artificial penetrations and other factors;  (2) The monitoring frequency and spatial distribution of monitoring wells must be based on baseline geochemical data that has been collected under § 146.82(a)(6) and any modeling results in the area of review evaluation required by § 146.84(b); 

(d) Periodic monitoring of the ground 

and geochemical changes above the confining may be a result of carbon dioxide movemenconfining zone or additional identified zones:

(1) The location and number of mo

must be based on specific information about sequestration project, including injection rate geology, the presence of artificial penetratiofactors;

(2) The monitoring frequency and spat

of monitoring wells must be based on baseline data that has been collected under § 146.82(modeling results in the area of review evaluatio§ 146.84(b);

146.90 (e) A demonstration of external mechanical integrity 

pursuant to § 146.89(c) at least once per year throughout the duration of the geologic sequestration project;  (f) A pressure fall-off test at least once every five years unless more frequent testing is required by the Director based on site specific information; 

(e) A demonstration of external mecha

pursuant to § 146.89(c) at least once per year tduration of the geologic sequestration project;

(f) A pressure fall-off test at least on

years unless more frequent testing is required bbased on site specific information;
Carbon Sequestration Council (CCS Contact Group) 36 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

 (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); 

(g) Testing and monitoring to track the 

carbon dioxide plume and the position of the by either monitoring for pressure changes formation overlying the confining zone or ugeophysical techniques (e.g., seismic, electricelectromagnetic surveys and/or down-hole cdetection tools);

146.90 (h) At the Director’s discretion, surface ai

monitoring and/or soil gas monitoring to detect movement of carbon dioxide that could endanger a USDW. 

r 

 (1) The testing and monitoring plan must be based on potential vulnerabilities within the area of review;  (2) The monitoring frequency and spatial distribution of surface air monitoring and/or soil gas monitoring must reflect baseline data and the monitoring plan must include how the proposed monitoring will yield useful information on the area of review delineation and/or compliance with standards under 40 CFR 144.12; 

(h) At the Director’s discretion, surface 

and/or soil gas monitoring to detect movemedioxide that could endanger a USDW.

(1) The testing and monitoring plan m

on potential vulnerabilities within the area of rev

(2) The monitoring frequency and spat

of surface air monitoring and/or soil gas moreflect baseline data and the monitoring plan how the proposed monitoring will yield useful ithe area of review delineation and/or comstandards under 40 CFR 144.12;

146.90(i) (i) Any additional monitoring, as required by the 

Director, necessary to support, upgrade, and improve computational modeling of the area of review evaluation required under § 146.84(b) and to determine compliance with standards under 40 CFR 144.12; and  (j) A quality assurance and surveillance plan for all testing and monitoring requirements. 

(i) Any additional monitoring, as req

Director, necessary to support, upgrade, computational modeling of the area of revierequired under § 146.84(b) and to determine costandards under 40 CFR 144.12; and

(j) A quality assurance and surveillanc

testing and monitoring requirements.

146.91 11. Reporting requirements. 

The owner or operator must, at a minimum, provide the following reports to the Director, for each permitted Class VI well:  (a) Semi-annual reports containing: 

The owner or operator must, at a minimumfollowing reports to the Director, for each permwell:  (a) Semi-annual or less frequent at the the Director reports containing:  (1) Any significant changes to the phys
Carbon Sequestration Council (CCS Contact Group) 37 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

 (1) Any changes to the physical, chemical and other relevant characteristics of the carbon dioxide stream from the proposed operating data;  (2) Monthly average, maximum and minimum values for injection pressure, flow rate and volume, and annular pressure; 

and other relevant characteristics of the castream from the proposed operating data;  (2) Monthly average, maximum and mifor injection pressure, flow rate and volume, pressure; 

146.91(a) (3) A description of any event that exceeds 

operating parameters for annulus pressure or injection pressure as specified in the permit;  (4) A description of any event which triggers a shutdown device required pursuant to § 146.88(e) and the response taken;  (5) The monthly volume of the carbon dioxide stream injected over the reporting period and project cumulatively;  (6) Monthly annulus fluid volume added; and  (7) The results of monitoring prescribed under § 146.90. 

 (3) A description of any significan

exceeds operating parameters for annulus injection pressure as specified in the permit;  (4) A description of any significant triggers a shutdown device required pursuant and the response taken;  (5) The monthly volume of the castream injected over the reporting period cumulatively;  (6) Monthly annulus fluid volume added (7) The results of monitoring prescr146.90. 

 (b) Report, within 30 days the results of:  (1) Periodic tests of mechanical integrity;  (2) Any other test of the injection well conducted by the permittee if required by the Director; and  (3) Any well workover.  (c) Owners or operators must submit reports in an electronic format acceptable to the Director. At the 

discretion of the Director, other formats may be accepted. 

Support the proposed language. 

146.92 12. Injection well plugging. 

 (a) Prior to the well plugging, the owner or operator must flush each Class VI injection well with a buffer fluid, determine bottomhole reservoir pressure, and perform a final mechanical integrity test. 

 (a) Prior to the well plugging, the ownmust flush each Class VI injection well with determine bottomhole reservoir pressure, and pexternal mechanical integrity test of any rele

materials remaining.
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Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

146.92(b) (b) Well Plugging Plan. The owner or operator of a 

Class VI well must prepare, maintain, and comply with a plan that is acceptable to the Director. The requirement to maintain and implement an approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. The well plugging plan must be submitted as part of the permit application and must include the following information: 

Support the proposed language. 

 (1) Appropriate test or measure to determine bottomhole reservoir pressure;  (2) Appropriate testing methods to ensure mechanical integrity as specified in § 146.89;  (3) The type and number of plugs to be used;  (4) The placement of each plug including the elevation of the top and bottom of each plug;  (5) The type and grade and quantity of material to be used in plugging. The material must be compatible with the carbon dioxide stream; and  (6) The method of placement of the plugs. 

 (1) Appropriate test or measure bottomhole reservoir pressure;  (2) Appropriate testing methods to external mechanical integrity as specified in §14

 (3) The type and number of plugs to be  (4) The placement of each plug elevation of the top and bottom of each plug;  (5) The type and grade and quantity be used in plugging. The material must be suwith the carbon dioxide stream; and  (6) The method of placement of the plu

 (c) Notice of intent to plug. The owner or operator must notify the Director at least 60 days before plugging of a well. At this time, if any changes have been made to the original well plugging plan, the owner or operator must also provide the revised well plugging plan. At the discretion of the Director, a shorter notice period may be allowed. 

Support the proposed language. 

146.92(d) (d) Plugging report. Within 60 days after plugging 

or at the time of the next semi-annual report (whichever occurs earlier) the owner or operator must submit a plugging report to the Director. If the semi-annual report is due less than 15 days after completion of plugging, then the report must be submitted within 60 days after plugging. The report must be certified as accurate by the owner or operator and by the person who performed the plugging operation (if other than the owner or operator.) 

 (d) Plugging report. Within 60 days the owner or operator must submit a plugging Director. If the semi-annual report is due less 

after completion of plugging, then the repsubmitted within 60 days after plugging. The r

certified as accurate by the owner or operatoperson who performed the plugging operation the owner or operator.) 

146.93 13. Post-injection site care and site closure 

 (a) The owner or operator of a Class VI well must 

Post-injection site care and site closure  (a) The owner or operator of a Class 
Carbon Sequestration Council (CCS Contact Group) 39 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

prepare, maintain, and comply with a plan for post-injection site care and site closure that meets the requirements of paragraph (a)(2) of this section and is acceptable to the Director.  (1) The owner or operator must submit the postinjection site care and site closure plan as a part of the permit application to be approved by the Director. 

prepare, maintain, and comply with a plan for site care and site closure that meets the reparagraph (a)(2) of this section and is acceDirector.  (1) The owner or operator must sub

injection site care and site closure plan as permit application to be approved by the D

continue to conduct monitoring as specified in approved post-injection site care and site pursuant to the performance based criteria 146.93(b)(3).

 (2) The post-injection site care and site closure plan must include the following information:  (i) The pressure differential between pre-injection and predicted post-injection pressures in the injection zone; (ii) The predicted position of the carbon dioxide plume and associated pressure front at site closure as 

demonstrated in the area of review evaluation required under § 146.84(b); 

 (2) The post-injection site care and sit

must include the following information:

(i) The pressure differential between 

and predicted post-injection pressures in the inj

(ii) The predicted position of the ca

plume and associated pressure front at sitdemonstrated in the area of review evaluation r§ 146.84(b);

146.93(a)(2) (iii) A description of post-injection monitoring 

location, methods, and proposed frequency; and  (iv) A proposed schedule for submitting postinjection site care monitoring results to the Director. 

 (iii) A description of post-injectio

location, methods, and proposed frequency; an

(iv) A proposed schedule for submitting 

site care monitoring results to the Director.

 (3) Upon cessation of injection, owners or operators of Class VI wells must either submit an amended postinjection site care and site closure plan or demonstrate to 

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

Support the proposed language. 

(4) The owner or operator may modify and resubmit the post-injection site care and site closure plan for the Director’s approval within 30 days of such change. 

 4) At any time during the post-injecphase, the owner or operator may modify and post-injection site care and site closure plan for approval within 30 days of such change. 
Carbon Sequestration Council (CCS Contact Group) 40 

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146.93(b) (b) The owner or operator shall monitor the site 

following the cessation of injection to show the position of the carbon dioxide plume and pressure front and demonstrate that USDWs are not being endangered.  (1) The owner or operator shall continue to conduct monitoring as specified in the Director-approved postinjection 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. 

 (b) The owner or operator shall mofollowing the cessation of injection to show the 

carbon dioxide plume and pressure front and that USDWs are not being endangered. 

 (1) The owner or operator shall continmonitoring as specified in the Director-apinjection site care and site closure plan, unauthorized pursuant to 146.93(b)(3).

146.93(b) (2) If the owner or operator can demonstrate to the 

satisfaction of the Director before 50 years, based on monitoring and other site-specific data, that the geologic sequestration project no longer poses an endangerment to USDWs, the Director may approve an amendment to the post-injection site care and site closure plan to reduce the frequency of monitoring or may authorize site closure before the end of the 50-year period. 

 (2) If the owner or operator can demonstrate to the satisfaction of the Direc

years, based on monitoring and other site-spethe geologic sequestration project no longendangerment to USDWs, the Director may amendment to that the post-injection site c

closure plan should be revised to reduce the 

monitoring, the Director shall approve the redu

authorize site closure before the end of the 50-y

 (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. 

 (3) Prior to authorization for site closuor operator must demonstrate to the Directmonitoring, other site-specific data, and moreasonably consistent with site performanadditional monitoring is needed to assure thasequestration project does not and is not expan endangerment to USDWs. The Director closure if the owner or operator demonstrates, current understanding of the site, including mand/or modeling, all of the following: (i) tmagnitude and extent of the project footprint and the area of elevated pressure) ; (ii) tlocation of the detectable CO2 plume; (iii) thasignificant leakage of either CO2 or displacfluids that is endangering USDWs; (iv) that thdisplaced fluids are not expected to migrate in manner that encounters a potential leakage pUSDW; (v) that the injection wells at the site cor through the injection zone or confining zone and abandoned in accordance with these requ
Carbon Sequestration Council (CCS Contact Group) 41 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

(vi) any remaining project monitoring wells abeing managed by a person and in a manner the Director.

 (4) If such a demonstration cannot be made (i.e., if the carbon dioxide plume and pressure front have not stabilized) after the 50-year period, the owner or operator must submit to the Director a plan to continue post-injection site care. 

 (4) If such a demonstration cannot be 

the carbon dioxide plume and pressure frostabilized) after the 50-year period, the ownemust submit to the Director a plan to continue site care.

146.93(c) (c) Notice of intent for site closure. The owner or 

operator must notify the Director at least 120 days before site closure. At this time, if any changes have been made to the original post-injection site care and site closure plan, the owner or operator must also provide the revised plan. 

At the discretion of the Director, a shorter notice period may 

be allowed. 

Support the proposed language. 

146.93(d) (d) After the Director has authorized site closure, 

the owner or operator must plug all monitoring wells in a manner which will not allow movement of injection or formation fluids that endangers a USDW. 

Support the proposed language. 
Carbon Sequestration Council (CCS Contact Group) 42 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

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

within 90 days that must thereafter be retained at a location designated by the Director. The report must include:  (1) Documentation of appropriate injection and monitoring well plugging as specified in § 146.92 and paragraph (c) of this section. The owner or operator must provide a copy of a survey plat which has been submitted to 

the local zoning authority designated by the Director. The 

plat must indicate the location of the injection well relative to permanently surveyed benchmarks. The owner or operator must also submit a copy of the plat to the Regional Administrator of the appropriate EPA Regional Office; 

 (e) Once the Director has authorizesd 

the owner or operator must submit a site closur90 days that must thereafter be retained 

designated by the Director. after completion 

operations. The report must include:  (1) Documentation of appropriate monitoring well plugging as specified in paragraph (c) of this section. The owner or oprovide a copy of a survey plat which has been the local zoning authority designated by the plat must indicate the location of the injection wto permanently surveyed benchmarks. The ownmust also submit a copy of the plat to Administrator of the appropriate EPA Regional O

 (2) Documentation of appropriate notification and information to such State, local and tribal authorities as have authority over drilling activities to enable such State and local authorities to impose appropriate conditions on subsequent drilling activities that may penetrate the injection and confining zone(s); and  (3) Records reflecting the nature, composition and volume of the carbon dioxide stream. 

Support the proposed language. 

146.93 (f) Each owner or operator of a Class VI injection 

well must record a notation on the deed to the facility property or any other document that is normally examined during title search that will in perpetuity provide any potential purchaser of the property the following information:  (1) The fact that land has been used to sequester carbon dioxide;  (2) The name of the State agency, local authority, and/or tribe with which the survey plat was filed, as well as the address of the Regional Environmental Protection Agency Office to which it was submitted; and 

Support the proposed language. 
Carbon Sequestration Council (CCS Contact Group) 43 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

 (3) The volume of fluid injected, the injection zone or zones into which it was injected, and the period over which injection occurred.  (g) The owner or operator must retain for three years following site closure, records collected during the post-injection site care period. The owner or operator mustdeliver the records to the Director at the conclusion of the retention period, and the records must thereafter be retained at a location designated by the Director for that purpose. 

Support the proposed language. 

146.94 14. Emergency and remedial response. 

 (a) As part of the permit application, the owner or operator must provide the Director with an emergency and remedial response plan that describes actions to be taken to address movement of the injection or formation fluids that may cause an endangerment to a USDW during construction, operation, closure and post-closure periods. 

 (a) As part of the permit application, operator must provide the Director with an emebased remedial response plan that describes taken to address movement of the injection fluids that may cause an endangerment to a construction, operation, closure and post-closur

.146.94(b) (b) If the owner or operator obtains evidence that 

the injected carbon dioxide stream and associated pressure front may cause an endangerment to a USDW, the owner or operator must:  (1) Immediately cease injection;  (2) Take all steps reasonably necessary to identify and characterize any release;  (3) Notify the Director within 24 hours; and  (4) Implement the emergency and remedial response plan approved by the Director. 

 (b) If the owner or operator obtains the injected carbon dioxide stream, displaced foor and associated pressure front may 

endangerment to endangers a USDW, the own

must:  (1) Immediately Cease injection in a pr

considering circumstances.  (2) Take all steps reasonably necessand characterize the endangerment posed;  (3) Notify the Director or the representative within 24 hours of becoming endangerment; and 
Carbon Sequestration Council (CCS Contact Group) 44 

Rule Provisions EPA Rule Issue Proposed CCS Group Recommendati

 (c) The Director may allow the operator to resume injection prior to remediation if the owner or operator demonstrates that the injection operation will not endanger USDWs. 

Support the proposed language. 

 (d) The owner or operator must notify the Director 

and obtain his approval prior to conducting any well workover. 

 (d) The owner or operator must notifprior to conducting any well workover in rescase of endangerment.
Docket ID No. EPA–HQ–OW–2008–0390 

Carbon Sequestration Council 1 December 23, 2008 

Attachment B: Comments and Recommendations of the Carbon Sequestration Council on 

Issues on which EPA Requested Comments in the Geologic Sequestration Proposal

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

73 FR 43497 1. EPA seeks comment on any aspects of 

the ongoing State efforts to regulate the GS of 

CO2 and how these efforts might be used to 

better inform a final Federal rulemaking. EPA 

Notice 43497. 

Use state approaches as examples to support 

recommendations where appropriate. As EPA 

moves toward finalizing this rule, EPA should monitor 

state rulemaking to assess the extent to which its rule 

needs to afford state Director’s the flexibility to 

account for regional differences. We also support the 

implementation of separate primacy for Class VI 

separately from other classes of wells. 

73 FR 43502 2. Injection of CO2 for the purposes of 

enhanced oil and gas recovery (EOR/EGR), as 

long as any production is occurring, will 

continue to be permitted under the Class II 

program. EPA seeks comment on the merits of 

this approach since owners or operators of 

some Class II EOR/EGR wells may wish to use 

wells for the purposes of production and GS 

prior to the field being completely depleted. 

EPA Notice 43502. 

EOR needs to be maintained under the current Class 

II program and any storage that occurs under EOR 

should continue to be handled under the Class II 

program. CSC supports the language developed by 

the multi-stakeholder discussion (MSD) group that 

would make this more explicit. 

We also support the absence of an economic test for 

oil and gas reservoir “depletion.” The MSD group 

has developed language for differentiating between 

wells in oil and gas reservoirs that should be 

permitted under the current Class II program 

requirements and those that should be permitted 

under other provisions (preferably as Class II wells 

subject to enhanced requirements). 

146.81(c) 3. EPA seeks comment on the approach 

to grandfather construction requirements at the 

Director’s discretion for existing Class I, Class 

II, and Class V wells seeking to convert to Class 

VI wells, and whether additional construction 

requirements would be necessary to prevent 

endangerment to USDWs from the GS of CO2. 

EPA Notice 43502. 

CSC strongly supports a regulatory approach that 

would facilitate the transition of existing wells 

constructed to Class I, Class II and Class V 

standards to GS wells regulated under provisions of 

the proposed rule. In all cases, such existing wells 

will have been permitted under conditions sufficient 

to protect USDWs and will have a demonstrated 

record of performance under their existing operations 

and MIT programs that can be used as a basis for 

conversion to the Class VI program or (in the case of 

GS wells in depleted oil and gas reservoirs) to 

enhanced Class II requirements. In particular, wells 

constructed to current Class II standards with 

demonstrated success in CO2 service should be 

eligible for grandfathering with minimal steps such as 

notification and permit modifications to add any 

additional requirements necessary to address 

geologic containment of injected carbon dioxide 

streams. Wells with this performance record should 

not require any additional structural requirements to 

ensure protection of USDWs because of their 

demonstrated success. 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 2 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

146.81(c) 4. Additionally, EPA seeks comment on 

how the grandfathering approach for existing 

wells may affect compliance with the other 

requirements in its proposal. EPA Notice 

43502. 

All components of the existing wells with a proven 

record of performance should be grandfathered 

unless there are specific USDW endangerment 

concerns identified by the Director. See Comment 

above. 

144.6(f) 

146.5 

146.81 

5. EPA is proposing to preclude the 

injection of CO2 for long-term storage into coal 

seams where they are above the lowermost 

USDW. EPA requests comment on this 

proposed prohibition. EPA Notice 43503. 

CSC opposes this restriction. Qualification of a 

formation for storage should be based on 

performance-based standards and site-specific 

considerations. Because we recommend allowing 

GS in formations that may be above the lowermost 

USDW, the rule should clearly provide that GS would 

only be allowed into an injection zone for which 

Director determines that geologic and other 

conditions exist that will prevent fluid movement that 

endangers USDWs above or below. 

There are significant differences in geology from one 

area of the country to another. Rather than impose 

an arbitrary limit based on the depth of the lowermost 

USDW or a specific minimum depth restriction, EPA 

should follow its stated objective and use a 

performance standard that is clearly spelled out and 

can be met with appropriate demonstrations of 

containment. 

144.6(f) 

146.5 

146.81 

6. The location and proximity of other 

formations to USDWs may preclude their use 

for GS. EPA seeks comment on prohibiting 

injection into such formations if they are above 

the lowermost USDW. EPA Notice 43503. 

Restricting injection to formations below the 

lowermost underground source of drinking water or 

USDW is not necessary for the protection of USDWs 

and would remove a vast number of viable 

formations from consideration. Industry has shown 

that it can operate CO2 injection wells in an EOR 

context without endangering USDWs that are located 

below the injection zone. An excellent example is the 

Salt Creek EOR project in Wyoming, which has a 

USDW below the injection zone. Moreover, under 

the proposed rule, there are other measures that 

would provide real assurance of formation integrity 

and require operators to demonstrate that their 

project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. 

In conjunction with this recommendation, CSC also 

recommends that all GS into basalts, coal seams, 

and salt domes be conducted under Class V as 

experimental wells initially and then as commercial 

scale Class V wells/projects as the experimental 

projects or other factors allow applicants to 

demonstrate that these sites can be suitable for 

geological sequestration while preventing 

endangerment of USDWs. 

Keeping these wells under Class V would allow EPA 

and the states to gain experience in developing 

suitable permitting requirements for such wells and to 

tailor those requirements until the agencies are ready 

to adapt the Class VI regulations or other 

requirements as appropriate. 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 3 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

146.81(b) 

146.81(d) 

7. By defining “carbon dioxide stream” to 

exclude hazardous wastes (146.81(d)), EPA’s 

rule, if finalized, assures that it would apply only 

to CO2 streams that are not hazardous wastes 

as defined in 40 CFR Part 261. As a result, 

EPA’s proposed rule would preclude the 

injection of hazardous wastes in Class VI 

injection wells. EPA seeks comment on this 

approach and other considerations associated 

with the presence of “impurities” in the CO2 

stream. EPA Notice 43503. 

CSC agrees with the concept that Class VI wells 

should not be injecting hazardous wastes, but there 

are believed to be few, if any, circumstances under 

which RCRA hazardous waste provisions would 

apply to CO2 streams. Current capture technologies 

under development are not likely to produce a CO2 

stream that would ever meet the definition of 

hazardous waste under 40 CFR 261. These CO2 

capture technologies will yield a relatively pure CO2 

stream, one that is unlikely to contain sufficient 

hazardous constituents to qualify as hazardous under 

any circumstances. To begin with, those CO2 

streams will constitute uncontained gas that is not 

even a solid waste under RCRA. Moreover, the 

captured supercritical streams will not be susceptible 

to normal RCRA testing protocols because of the 

physical characteristics of supercritical CO2. 

In addition, we are proposing some modifications to 

EPA’s definition of CO2 stream in the rule. The 

modifications reflect the fact that the source of CO2 

should not be a factor in the context of defining the 

CO2 stream. The rule applies to the injection of CO2 

and should not address the origins of the materials 

since that is beyond the scope of this regulation. The 

original text would have precluded injection of CO2 

from some sources. The question of how CO2 

should be accounted for, and from what sources, in a 

GHG management and accounting system is beyond 

the scope of this regulation. 

More to the issue of “impurities”, CSC objects to any 

mandated purity standards for CO2. The inclusion of 

impurities in stored CO2 should not be arbitrarily 

prohibited; however, it is recognized that the 

presence of those impurities at sufficient 

concentrations may trigger the applicability of other 

statutory limits or requirements. Determining the type 

and levels of impurities in the CO2 stream is – absent 

a compelling public or environmental health risk – 

best left to contractual negotiations between parties 

in a CCS value chain as opposed to an arbitrary 

regulatory determination. The contracting parties are 

best able to evaluate the types of impurities, their 

compatibility with the reservoir and equipment, and 

determine the acceptable levels of those impurities in 

the stored CO2. If there were ever any overriding 

public interest in limiting either the type or level of 

contaminants, principles of cost-effectiveness and 

risk-management should guide the decision making 

process. 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 4 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

73 FR 43504 8. Class VI requirements and permits will 

need to be carefully structured to ensure that 

they do not “authorize” inappropriate hazardous 

releases. This would include clarifying if there 

are potential releases from the well which are 

outside the scope of the Class VI permit. EPA 

requests comment on particular situations 

where this might occur. EPA notice 43504. 

Well chosen sites should prevent these conditions 

from occurring. At the same time, permit writers 

should not write permits so restrictive as to make the 

undertaking of a GS project untenable. EPA should 

remember that CERCLA liability will not only impact 

owners and operators of GS projects, but also 

hundreds, thousands, and even more numerous pore 

space owners. EPA should consider the threat of 

subjecting these pore space owners to CERCLA 

liability. Their property interests in the CO2 GS 

project injection zones could subject them to strict, 

joint, and several liability under CERCLA pursuant to 

whatever liability theories might be developed by 

future litigants seeking compensation for response 

and remediation costs incurred in the cleanup of 

releases from geologic sequestration injection zones. 

EPA should recognize the significant chilling effect 

CERCLA liability concerns will have on GS projects, 

and seize the opportunity in this rulemaking to 

alleviate any CERCLA liability concerns to the 

greatest extent possible. 

73 FR 43504 9. EPA also requests comment on other 

considerations associated with the presence of 

impurities in the CO2 stream related to 

CERCLA. EPA Notice 43504. 

CSC is concerned that potential CERCLA liabilities 

will have the potential to chill enthusiasm for 

undertaking GS projects. EPA needs to respond 

clearly and positively to this concern by developing 

appropriate language in the regulations and permits 

to provide the clarity and assurance needed to 

promote continued research and development for GS 

projects. 

73 FR 43506 10. EPA’s 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 dissipation. EPA says 

that these layers could provide additional sites 

for monitoring, mitigation, and remediation. 

EPA’s proposal would not require that these 

additional zones be identified for all GS sites 

because their absence does not necessarily 

indicate inappropriateness of a GS site. 

However, if such zones are present, information 

about their characteristics can provide inputs for 

predictive models, identify appropriate 

monitoring locations, and improve public 

confidence in and acceptance of a proposed 

GS site. EPA specifically seeks comment on the 

merits of requiring the identification of these 

additional zones. EPA Notice 43506. 

Secondary containment should not be mandatory. 

There are many areas where a single confining zone 

can be shown to be highly protective of USDWs. 

Adequacy of containment must be demonstrated on 

a site-specific basis. By definition, an additional 

confining or containment zone beyond is not 

necessary to prevent endangerment of USDWs, and 

would serve only to prevent the use of otherwiseappropriate GS reservoirs. 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 5 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

146.82(c) 

146.84 

146.90(d)(2) 

11. EPA proposes that the owners or 

operators of GS wells be required to delineate 

the AoR for CO2 GS sites using computational 

fluid flow models designed for the specific site 

conditions and injection regime. EPA seeks 

comment on the use of modeling for AoR 

delineation. EPA Notice 43506. 

Modeling is well developed technology that can 

readily simulate complex behavior of injected CO2. It 

should be one of the techniques used to delineate 

the AoR. 

The oil and gas industry has a great deal of 

experience that can be generally applied in the 

delineation of the AoR. 

The most complex model is not always necessary to 

adequately delineate the AoR. Some CO2 EOR 

projects have successfully operated for decades 

using only production data and pressure mapping, 

which has in effect defined AoR. 

146.84 12. In some cases, owners or operators 

may choose to use proprietary models (i.e., not 

available for free to the general public). EPA 

says it is aware that the use of proprietary 

codes may prevent full evaluation of model 

results (e.g., NRC, 2007). Several popular 

codes in the petroleum-reservoir engineering 

discipline are proprietary and owners or 

operators of particular sites may prefer to use 

these codes as they have previous experience 

with them, and they have been used in peerreviewed studies to model CO2 sequestration. 

When using a proprietary model, owners or 

operators should clearly disclose the code 

assumptions, relevant equations, and scientific 

basis. EPA seeks comment on allowing the use 

of proprietary models for GS sites. EPA Notice 

43507. 

Use of proprietary models should be allowed. EPA’s 

Confidential Business Information requirements 

should apply to any proprietary model used. 

146.84 13. EPA seeks comment on the 

applicability of computational fluid flow models 

for delineating the AoR of GS sites. EPA Notice 

43507. 

Computational fluid flow models can inform the 

delineation of the AoR. (See also Comment on 

Question 11 above.) 

146.84 14. 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 43507. 

Rather than a fixed time period, CSC recommends 

following a performance based approach that would 

require reevaluation of the AOR as, but only as, it is 

necessary, as determined by consideration of 

whether there are significant unexpected changes in 

injection parameters or monitoring results. 

146.84(f) 15. EPA proposes to allow a phased 

approach to corrective action but says this may 

not be appropriate in all situations; therefore 

EPA is proposing that the Director have the 

discretion to decide to allow this approach, 

based on the understanding of relevant 

geologic and site conditions. EPA invites public 

comment on the merits and frequency of 

reevaluation of the AoR as well as the phased 

corrective action approach for GS wells. EPA 

CSC supports the EPA proposal. The phased 

approach allows the sound economic execution of 

the project over time without endangering USDWs. 

This approach prevents an operator from the 

unnecessary expense of remediating wells in an area 

that ultimately may not be affected by the storage 

project. Frequency of reevaluation should be based 

on site performance as noted in the prior comment. 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 6 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

Notice 43508. 

146.86(b) 16. 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 43509. 

Generally the surface casing is set below the lowest 

USDW above the confining zone, but it should be 

recognized that this is not appropriate in all geologic 

settings. In some areas USDWs can extend to much 

greater depths than would be appropriate for setting 

of surface casing. Regulations should recognize 

these situations and allow a surface casing setting 

depth that may not fully cover the USDWs. 

CSC opposes the requirement for cementing the long 

string casing back to surface. Cementing 

requirements should focus on ensuring competent 

isolation and seal across the injection zone and 

confining zone(s). Sealing the annulus between the 

long string and surface casing could limit an 

operators ability to monitor for leakage or conduct 

remedial operations. 

Regarding packer setting depth, the director should 

retain discretion for allowing variation from this 

requirement. 

146.81(c) 17. EPA also seeks comment on how the 

proposed grandfathering provisions for existing 

wells (construction requirements) may affect 

compliance with the above, proposed 

construction requirements. EPA Notice 43509. 

By definition, the construction of previously-permitted 

wells has already been determined to be sufficient for 

protection of USDWs. Consequently, additional 

construction-related requirements should not be 

imposed in the absence of specific evidence of a 

construction-related deficiency creating a potential for 

endangerment. Because the act of injection would 

be the same for CO2 EOR and CO2 storage, wells in 

CO2 service constructed to Class II well standards 

should presumptively be sufficient to protect USDWs.

146.86 18. EPA seeks comment on the merits of 

horizontal well drilling techniques for GS wells 

and the applicability of well construction 

requirements discussed in this proposal. EPA 

Notice 43509. 

Drilling of directional and horizontal wells is an 

established technology that can significantly reduce 

surface impacts of a GS project and improve the 

injection rate of a well. CO2 injection wells at In 

Salah, Sleipner, and in many Texas locations are 

horizontal or have horizontal sections. 

146.86 

73 FR 43510 

19. EPA seeks comment regarding 

requirements for degradation-resistant well 

construction materials, such as acid-resistant 

cements and corrosion resistant casing. EPA 

Notice 43510. 

The well should be looked at as a system such that 

not each individual component needs to be CO2 

resistant as long as the entire system provides an 

effective barrier under the subsurface conditions. 

Industry experience with CO2 EOR strongly supports 

the use of conventional oil field tubing, casing, and 

cements. Industry experience over the past 35 years 

has led to the development of corrosion mitigation 

measures (e.g. plastic or epoxy lined tubing, use of 

corrosion inhibitors, and proper dehydration of CO2) 

that provide a high degree of protection and mitigate 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 7 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

any corrosive effects of injected CO2. 

146.88(a) 20. EPA is requesting comment on the 

extent 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 43511. 

The use of fracturing for stimulation is appropriate 

and should be allowed provided that there is no 

damage to the confining unit that would result in 

endangerment of USDWs. There are computer 

simulators to predict fracture behavior so the impact 

on the confining zone can be anticipated. 

73 FR 43511 21. EPA is also requesting information to 

better qualify the use of fracturing for GS 

injection in specific geologic settings and rock 

formation lithologies. EPA Notice 43511. 

EPA should allow fracturing for stimulation and 

should set injection pressure limits to preclude 

initiating, propagating, or opening avenues of release 

through fractures transecting the confining zone. 

146.88(e) 22. EPA seeks comment on the merits of 

requiring down-hole shut-off valves in GS wells. 

EPA Notice 43511. 

Over-pressure protection is best achieved by 

ensuring compatibility of the casing/tubing material 

design strength with the surface injection 

(compression) system. Down-hole shut-in devices 

are not appropriate for this application. These 

devices are installed in the tubing string and are 

typically near the surface of the well. They are used 

in off-shore applications where they are intended to 

seal the tubing at or near the ocean floor in the event 

that the tubing is severed above that point. These 

devices were not designed for use deep underground 

and would provide little if any protection to USDWs. 

It is not practicable to install these devices deep 

underground (e.g. shortly above the packer). 

Additionally these devices would create a restriction 

on running other tools like logging tools in the well 

and therefore could limit an operator’s ability to do 

required monitoring and diagnostic work. Lastly, 

these devices require periodic testing and 

maintenance which could require either pulling the 

device by wireline or by pulling the entire tubing 

string depending on the type of device installed. 

Either of these activities would be disruptive and 

costly to the overall project operations. 

144.6(f) 

146.5 

146.81 

23. EPA is aware that the proposal to limit 

CO2 injection to reservoirs below the lowermost 

USDW may preclude injection into certain 

geologic formations currently under 

consideration for GS. As a result, the Agency is 

considering and requesting comment on 

alternative approaches that would allow 

injection between and/or above the lowermost 

Injection above the lowest USDW should be allowed 

as long as the operator can demonstrate 

confinement above and below the injection formation.

Retaining the proposed restriction would remove a 

significant number of viable formations from 

consideration. It has been shown that CO2 injection 

wells can be operated in an EOR context without 

endangering USDWs that are located below the 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 8 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

USDW, thus potentially allowing more areas to 

be available for GS while preventing USDW 

endangerment. EPA Notice 43512. 

injection zone. An excellent example is the Salt 

Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the 

proposed rule, there are other measures that would 

provide real assurance of formation integrity and 

require operators to demonstrate that their project will 

not endanger USDWs, making the lowermost USDW 

restriction unnecessary. 

144.6(f) 

146.5 

146.81 

24. EPA is soliciting comment on whether 

CO2 injection should be allowed into an 

injection zone above the lowermost USDW, 

when the Director determines that geologic 

conditions (e.g., thousands of feet of intervening 

formations between the injection zone and the 

overlying and/or underlying USDWs) exist that 

will prevent fluid movement into adjacent 

USDWs. EPA Notice 43512. 

See response to Question 23. CO2 injection zones 

should be selected based upon site specific 

evaluation of performance based criteria. 

“Thousands of feet of intervening formations” should 

not be necessary as long as it can be demonstrated 

that USDWs will be protected. 

73 FR 43512 25. EPA is also requesting comments on 

whether aquifer exemptions should be allowed 

for the purpose of Class VI injection, and under 

what conditions should such aquifer exemptions 

be approved. EPA Notice 43512. 

At this time, we do not recommend any specific need 

for new aquifer exemption criteria created because 

the existing criteria are perceived to be sufficient to 

allow aquifer exemptions as needed for GS. Even 

without changes, the aquifer exemption requirements 

in the UIC program would allow operators to obtain 

appropriate exemptions for GS operations. In 

addition, there should be no requirement that 

sequestration be below the lowermost USDW. 

Unfortunately – as the preamble to the proposed rule 

notes – the aquifer exemption process has effectively 

been disabled because EPA has sometimes refused 

to consider aquifer exemption requests for noninjection formations. 73 Fed. Reg. at 43512. Rather 

than preventing underground injection that 

"endangers drinking water sources" as the statute 

requires, this approach arbitrarily prevents injection 

that does not endanger any drinking water sources. 

This approach should be abandoned; instead, the 

aquifer exemption rules should be applied as written.

73 FR 43512 26. EPA seeks comment on whether the 

Agency should set a minimum injection depth 

requirement for CO2 GS, rather than require 

that such injection take place below the 

lowermost USDW. EPA Notice 43512. 

There should be no minimum depth for injection of 

CO2. The primary consideration should be 

protection of USDWs. A requirement for a minimum 

depth suggests an intention by EPA to require 

injection of CO2 in a supercritical phase. Such a 

requirement is not appropriate since there may be 

areas where injection of CO2 in other phases may be 

the only option. Again, site-specific evaluation and 

protection of USDWs should be the basis for 

determining depth of injection. 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 9 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

73 FR 43513-

15 

27. 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 43513. 

EPA should not mandate the use of tracers. The 

potential value of tracers is uncertain and too limited 

to justify their use in the injection well context. Any 

use of tracers should be entirely at the option of the 

operator. 

146.89(b) 28. EPA’s proposal would require owners 

or operators of Class VI GS projects to monitor 

internal mechanical integrity of their injection 

wells by continuously monitoring injection 

pressure, flow rate, and injected volumes, as 

well as the annular pressure and fluid volume to 

assure that no anomalies occur that may 

indicate an internal leak. EPA requests 

comment on the practicability of this 

requirement. EPA Notice 43513. 

There is concern regarding what constitutes 

continuous monitoring. Industry agrees that regular 

monitoring of the parameters identified by EPA is 

appropriate. Our experience with CO2 EOR strongly 

shows that daily monitoring of most of these 

parameters is adequate (exceptions to this would be 

on a site-specific basis). Recording should generally 

be done on a daily basis and reporting on a semiannual basis. As a guiding principle, the frequency of 

monitoring should be determined by the level of risk 

posed by the injection operation. 

146,89(c) 

146,90(e) 

29. EPA seeks comment on the appropriate 

frequency of internal and external MITs for GS 

injection wells, the appropriate types of MITs, 

and how to optimize MIT methods for GS. EPA 

Notice 43514. 

Timing for conducting MITs, should be based on risk 

and performance factors. Industry experience with 

CO2 EOR Class II program requires MITs every 5 

years. This frequency has proven protective of 

USDWs. Given the similarities between CO2 EOR 

wells and GS wells, CSC recommends 5-year 

frequency in this case as well. The MIT should test 

integrity of the long string casing, packer, and tubing 

and to the extent practicable, should test the integrity 

of the cement isolating the injection zone. There are 

many methods for conducting MITs. EPA should 

allow operators adequate flexibility in selecting the 

appropriate methods for their specific situation. API 

RP90 provides good examples of various methods 

for detecting mechanical failures, managing those 

risks, and conducting MITs. 

 

146.90 30. EPA seeks comment on the 

requirement for monitoring of GS sites for the 

purpose of tracking the location of the CO2 

plume and associated pressure front over time. 

EPA Notice 43514 

The amount of monitoring required to track plumes 

and pressure fronts is not cost justified in comparison 

with taking the necessary steps to demonstrate 

containment. The primary focus should be on 

making sure that the plume and formation fluid are 

contained within the injection zone rather than trying 

to show the exact location of the plume within that 

containment. 

The frequency of monitoring should be dictated by 

site-specific operational and geologic conditions 

combined with the results of monitoring. . 

146.90(f) 31. EPA’s proposal would require that 

owners or operators perform a pressure fall-off 

test at least once every five years. EPA seeks 

comment on the use and frequency of pressure 

fall-off testing for GS wells. EPA Notice 43515.

We recommend that an initial falloff test be 

conducted upon completion of the well prior to any 

operational injection and after the first year of 

operational injection. Following the first year, the 

frequency should be at the discretion of the Director 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 10 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

but the frequency should be aligned with the 

reevaluation of the AoR. 

146.90(g) 32. Based on information evaluated to date, 

EPA believes that tracking the plume and 

pressure front is an important companion step 

to address any uncertainties associated with 

initial AoR modeling and requests comment on 

this approach and more efficient alternatives 

that may be used to track the plume and 

pressure front. EPA Notice 43516. 

Uncertainties associated with AoR determinations 

may be addressed through the use of a conservative 

modeling approach. Requirements to “track” plumes 

or pressure fronts would be extraordinarily 

burdensome and are not necessary, as extensive 

experience with “no migration” exemptions for 

hazardous waste injection wells has shown. 

73 FR 43517 33. 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 43517. 

Monitoring techniques and frequency should be 

determined on a site-specific basis. Selection of 

monitoring types and frequency should balance the 

potential risks posed by the project with the cost and 

potential utility of monitoring. 

Surface and soil gas monitoring does not add value 

to the protection of USDWs. Many of the surface and 

soil gas monitoring techniques currently being 

evaluated lack the track record necessary for use in a 

regulatory compliance setting. Moreover, the 

potential for false-positives could undermine public 

confidence in GS technologies. 

146.90 

146.93(a) 

146.94(a) 

34. 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 post-injection site care and site 

closure plan. EPA seeks comment on the merits 

of requiring plans for monitoring, AoR, and postinjection site care as part of a permit 

application. EPA Notice 43517. 

The development of such plans is a good idea 

because it negates prescriptive regulation of the 

process. CSC is concerned that every modification 

of a plan may trigger a major permit modification, 

although it does not appear that current regulations 

would require that result. If major permit 

modifications were required, EPA would lose the 

adaptability desired for responding to experience 

gained from GS projects. 

It is unclear how the construction, operation, and 

closure of any monitor wells would be regulated, 

since these are not actual injection wells. 

Timing of development of plans should be linked to 

the actual activity being addressed (i.e. staged). It 

should not be necessary to prepare and submit a site 

closure plan or the post-closure monitoring plan at 

the start of the project, particularly considering that 

these activities will not occur for many years after the 

project starts. 

146.91 35. EPA seeks comment on the frequency 

of all proposed reporting requirements. EPA 

Notice 43517 

Frequency should reflect the level of risk associated 

with the activity. Semi-annual reporting is adequate. 

Reporting should be on a project basis as opposed to 

a well basis consistent with 146.23(c). 

146.91(c) 36. EPA seeks comment on the 

requirement for electronic reporting in its 

proposed rule. EPA Notice 43518. 

Industry’s objections to prior proposals for electronic 

reporting have been with the scope and breadth of 

information (incremental over written reports) that the 

Agency has previously proposed. Electronic 

reporting equivalent to existing written reports would 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 11 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

be acceptable to CSC. Until these concerns related 

to electronic reporting are resolved, such reporting 

may be encouraged but should not be required. 

73 FR 43518 37. In addition to the above recordkeeping 

and reporting requirements, EPA considered a 

requirement for owners or operators of GS sites 

to provide an annual report during the lifetime of 

the project, including the post-injection period, 

regarding the GS operation. 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 43518. 

An additional annual report is not necessary given 

the other reporting requirements in the Rule. 

Alternatively, if this report was to replace the other 

reporting requirements, there would be value to the 

proposal. 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 12 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

73 FR 43519-

20 

146.93(b) 

38. EPA is proposing using a combination 

of fixed timeframe and a performance standard 

as described above. EPA is tentatively 

proposing a post-injection site care (monitoring) 

period of 50 years with Director’s discretion to 

change that period to lengthen or shorten the 

50 year period if appropriate. EPA requests 

comment on the proposed use of a tentative 50 

year fixed timeframe that could be modified at 

the Director’s discretion based on monitoring 

and modeling data. EPA Notice 43519. 

We believe there are three problems with the closure 

standard in proposed section 146.93(b). First, the 

presumption that monitoring should continue for 50 

years is unnecessary and counterproductive. A 

straight performance standard is preferable to this or 

any other fixed time period because it provides a 

clearer standard and an incentive to maximize the 

understanding of site and project performance and as 

such is more protective of USDWs. Second, the 

proposal requires a showing that the CO2 plume has 

“stabilized”, which is undefined. Cessation of plume 

movement is not necessarily essential to show that a 

project poses no threat of endangerment to 

USDWs—plumes that are still moving may, 

nonetheless, remain contained. Instead, it is more 

protective to show that the plume is not expected to 

encounter a leakage pathway. Third, the required 

showing that “no additional monitoring is needed” 

does not provide guidance regarding how an 

operator is to show that no additional monitoring is 

needed. The proposal below provides specific 

guidance on what the operator must show. 

We recommend the standard in the proposed 

alternative language for section 146.93(b) because it 

sets forth detailed criteria, all of which must be 

satisfied, to demonstrate that the site does not pose 

an endangerment to USDWs. The specific criteria 

listed in our proposal will serve to provide the 

Director with the requisite information to make the 

appropriate determination. The advantage of this 

approach is that it establishes clear criteria that an 

operator must demonstrate before obtaining site 

closure based upon particular site characteristics and 

is, therefore, reasonably applicable to any storage 

site as opposed to a standard based upon a fixedduration. Furthermore, it is more stringent than a 

purely discretionary approach because it establishes 

specific criteria that must be shown before site 

closure may be granted. We believe this language, 

which is an extension of work done by the World 

Resources Institute and the Ground Water Protection 

Council, avoids the noted shortcomings and provides 

stronger protection for USDWs. 

This is the same recommendation as presented by 

the multi-stakeholder group, in which the Carbon 

Sequestration Council participated 

146.93 39. EPA is requesting comments on the 

proposed requirements for well plugging, postinjection site care, and site closure, including 

the proposed requirements for the post-injection 

time period. EPA Notice 43520. 

See response to Question 38 above regarding post 

closure time periods. 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 13 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

146.93(b)(2) 40. 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 43520. 

See response to Question 38 above regarding post 

closure time periods. 

144.36 41. Current UIC guidance describes trust 

funds as a form of financial assurance. The 

owner or operator may deposit funds into the 

trust fund in phases; that is, either over the term 

of the initial permit or over the remaining 

operating life of the injection well, as estimated 

in the well plugging plan, whichever period is 

shorter. Because of the possibility that the 

owner or operator may face financial distress 

prior to the trust being fully funded, 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. EPA Notice 

43521. 

Industry should have a variety of options for meeting 

financial assurance based upon the companies’ 

discretion. Options should include self-insurance, 

insurance, surety bonds or other appropriate financial 

instruments. 

73 FR 43521 42. 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 43521. 

EPA should leave the door open for establishing 

financial mechanisms on a project by project basis. 

The rulemaking should not prescribe or preclude 

particular financial instruments. The issue of 

financial assurance is complex and must be 

considered in significant detail and should be based 

on the initial experience gained from the use of FA 

mechanisms before any guidance or regulation is 

issued. 

73 FR 43522 43. EPA is assessing whether a financial 

ratings threshold for all companies using a selfguarantee, 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 43522. 

See response to Question 41 above. 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 14 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

146.85 44. EPA is requesting comments on 

whether financial responsibility mechanisms to 

be recommended in EPA guidance should be 

adjusted in the manner described, whether 

additional instruments should be included, and 

whether other adjustments to the financial 

responsibility mechanisms should be 

considered, all subject to EPA’s authority under 

the SDWA. EPA Notice 43522. 

See response to Question 41 above. 

73 FR 43522 45. The Agency is also requesting 

comment on allowing separate financial 

demonstrations to be submitted for the plugging 

of the injection well and for the post-injection 

site care requirements. EPA Notice 43522. 

We support the use of separate financial 

demonstrations for the plugging of the injection well 

and for the post-injection site care requirements 

based on the greater experience with well plugging 

requirements and methods. It will be easier to retain 

certainty for these actions and to use established FA 

methods. 

EPA should look into the options available for single 

bonding with phased release and multiple bonding, 

as is done under SMCRA. 

73 FR 43523 46. EPA requests comment on adopting the 

existing requirements for public participation at 

40 CFR Part 25 and 40 CFR Part 124 and 

whether additional requirements should be 

included to reflect the availability of new tools 

for disseminating and gathering information. 

Such tools include cable networks, the Internet, 

and other new technology. EPA Notice 43523. 

The current provisions in Parts 25 and 124 are 

sufficient to inform the public. Additional 

requirements should not be included. 

Public participation should be consistent across 

programs. If EPA believes the public participation 

requirements should be expanded, it should be done 

in a holistic manner across programs. 

73 FR 43522-

23 

47. EPA also requests comment on ways to 

enhance the public participation process, 

including engaging communities in the site 

characterization process as soon as candidate 

locations are identified. EPA Notice 43523. 

CSC does not believe that the public participation 

process should be extended to the site 

characterization stage of a GS project, particularly 

given that many sites might be characterized in the 

process of winnowing down the portfolio of potential 

sites. 

73 FR 43523 48. To gain authority for Class VI wells, 

States, Territories, and Tribes will be required to 

show that their regulations are at least as 

stringent as, and may be more stringent than, 

the proposed minimum Federal requirements 

(e.g., inspection, operation, monitoring, and 

recordkeeping requirements that well owners or 

operators must meet). Such Primacy States, 

Territories, and Tribes are authorized under 

Section 1422 of the SDWA. EPA Notice 43523.

States should be able to gain primacy as long as they 

meet the requirements of the UIC program for 

obtaining and retaining primacy. EPA should ensure 

that adequate funding is provided for the delegated 

program. 
December 23, 2008 

Carbon Sequestration Council (CCS Contact Group) 15 rfvanvoorhees@bryancave.com 

Rule Provisions 

or Federal 

Register Cite 

EPA Preamble Question CSC Response 

73 FR 43523 

73 FR 43529 

49. There may be benefits to parsing out 

primacy for Class VI wells, however EPA has 

not made a decision on this. Allowing States, 

Territories, and Tribes to acquire primacy for 

only Class VI wells may encourage them to 

assume the responsibility of implementation 

and provide for a more comprehensive 

approach to managing CCS projects (e.g., 

capture, transportation, and geologic 

sequestration). EPA is seeking comment on the 

merits and possible disadvantages of allowing 

primacy approval for Class VI wells 

independent of other well classes. EPA Notice 

43523. 

CSC supports separate primacy for Class VI. The 

geologic variation across the country justifies 

separate primacy determinations. The final rule 

should also preserve state authority to determine 

what agencies will exercise primacy. Moreover, EPA 

should provide adequate funding, which will require a 

substantial increase above current funding levels 

both to meet existing program needs and to provide 

the additional resources anticipated to be necessary 

for the Class VI program. These increases need to 

be provided in time to ramp up of resources, 

personnel, and training in advance of the anticipated 

heavy demand. 

144.36(a) 50. EPA proposes that Class VI injection 

well permits would be issued for the operating 

life of the GS project including the post-injection 

site care period. EPA seeks comment on the 

merits of this approach. EPA Notice 43523. 

A permit for the life of the project would ensure the 

continuity of operations. Shorter time periods would 

yield administrative burden without commensurate 

benefits. The development of AoR, plans, and other 

parts of the permitting process must be addressed on 

a project-wide basis. Therefore it is important for 

permits to last for the operating life. It is also 

sensible to allow for area permits. 

73 FR 43527 51. The Agency assumes three monitoring 

wells per injection well for the purpose of 

estimating national costs; however, the Agency 

recognizes that operators and primacy agency 

Directors may choose more or fewer monitoring 

wells depending on project site characteristics. 

Because the monitoring wells and associated 

costs represent a significant component of the 

Cost Analysis, the Agency acknowledges that 

this factor may be significant in the overall 

uncertainty of the Cost Analysis. EPA requests 

comment on whether three monitoring wells per 

injection well is an appropriate costing 

assumption. EPA Notice 43527. 

It is difficult to select a realistic ratio since each site 

will have its own characteristics that would 

significantly affect the number of monitoring wells 

necessary. Moreover, the potential benefit of any 

monitoring well must be determined and weighed 

against countervailing considerations. The potential 

for using “three monitoring wells per injection wells” is 

completely out of proportion to any prior experience 

in the UIC program and, hence, unsupportable. For 

many sites, monitoring wells should be unnecessary.

73 FR 43531 52. The public is invited to submit 

comments or identify peer-reviewed studies and 

data that assess the effects of early life 

exposure to changes in drinking water quality 

that may be caused by geologic sequestration 

of carbon dioxide. EPA Notice 43531. 

CSC is not aware of anything unique about CO2 

injection or its potential impacts on drinking water 

quality that would not be addressed within the 

existing drinking water program. The data EPA has 

on developing drinking water standards and MCLs 

can be used in this situation. 
December 23, 2008 

Cynthia C. Dougherty

Director 

Office of Ground Water and Drinking Water

U. S. Environmental Protection Agency

1200 Pennsylvania Ave., NW.

Washington, DC 20460

Dear Director Dougherty:

The organizations identified below submit these comments and recommendations to the 

Environmental Protection Agency (EPA) in response to the proposed rule for geologic 

sequestration of carbon dioxide under the Safe Drinking Water Act (SDWA). "Federal 

Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) 

Geologic Sequestration (GS) Wells", 73 Fed. Reg. 43491-541 (July 25, 2008), Docket ID No. EPA–

HQ–OW–2008–0390. We appreciated the extension of the public comment period that was 

granted by Assistant Administrator Benjamin Grumbles, announced in the Federal Register on 

November 21 and confirmed in your letter of November 24. The organizations submitting these 

recommendations represent a broad array of interests in the issues associated with this rulemaking 

and many of us have been discussing these interests and issues in an effort to reach consensus or at 

least narrow our differences. We used this extension period to continue efforts toward developing 

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

which EPA expressly requested comment and several other issues. We share your hope that these 

comments and recommendations will help the Agency develop a rule that will allow the technology 

to be permitted under an appropriate injection class while also ensuring protection of underground 

sources of drinking water as well as human health and the environment. 

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

gas (GHG) reductions." 73 Fed. Reg. 43492, 43495 (July 25, 2008). By the same token, the 

consensus recommendations presented in this letter are solely for the purpose of GS regulation 

under the Safe Drinking Water Act to protect USDWs and not for the purpose of addressing 

verification requirements for carbon credits. 

Enhanced recovery of oil or natural gas and geologic sequestration of CO2

EPA’s Proposal would continue to regulate and permit injection of CO2 for EOR/EGR purposes as 

Class II injection “as long as any production is occurring.” EPA has asked for comment on the 

merits of this approach “since owners or operators of some Class II EOR/EGR wells may wish to 

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

Fed. Reg. at 43502. We recommend that the rules be clarified to provide more certainty about the 

applicability of Class II requirements where GS of CO2 occurs in connection with EOR/EGR 

activities. Specifically, the UIC rules should provide a “bright line” definition as to the applicable 
Cynthia C. Dougherty 

December 23, 2008 

Page 2 

 

class of wells where CO2 injection for EOR/EGR production and for GS occur in tandem. We 

recommend the following language to accomplish that objective: 

§ 144.6, 144.80 and 146.5, and Classification of injection wells. 

Injection wells are classified as follows: 

* * * 

 (b) Class II. Wells which inject fluids: 

(1) Which are brought to the surface in connection with conventional oil or natural 

gas production and may be commingled with waste waters from gas plants which are 

an integral part of production operations, unless those waters are classified as a 

hazardous waste at the time of injection. 

(2) For enhanced recovery of oil or natural gas; 

(3) For storage of hydrocarbons which are liquid at standard temperature and 

pressure; 

(4) For enhanced recovery of oil or natural gas where geologic sequestration is 

occurring during or in connection with enhanced recovery of oil or natural gas 

provided (i) there is reasonable expectation of more than insignificant future 

production volumes or rates as a result of carbon dioxide injection and (ii) operating 

pressures are no higher than reasonably necessary to produce such volumes or rates; 

* * * 

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

except those wells described in subsection (b)(4) of this section or otherwise 

excluded from this Class.

1/

 

The undersigned have agreed that proposed language describing wells in classification (b)(4) 

establishes a “bright line” definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the current requirements 

of Class II. We have also agreed that the wells used for GS in oil and gas reservoirs that do not 

meet the criteria of (b)(4) should be subject to additional requirements. We have tentatively defined 

such wells as wells used “for geologic sequestration in oil and gas formations and where the criteria 

of paragraph (b)(4) are not met.” But we have not yet attempted to define what specific 

1/ Please note that well classification for geologic sequestration in certain formations is a matter still under 

discussion within the multi-stakeholder group and may be addressed further in future recommendations from 

the group. In the mean time individual participants in these discussions will be expressing views on this and 

other issues with an openness to revising their views if a consensus can be reached. 
Cynthia C. Dougherty 

December 23, 2008 

Page 3 

requirements should apply to these wells. We are committed to working toward agreement on those 

requirements (probably within a Class II context) and submitting the results of that effort to EPA by 

February 28, 2009 for your consideration. 

Injection Pressure Limitations

We are concerned about three aspects of proposed section 146.88(a), governing injection pressure 

limitations. First, it “restricts” fractures in the injection zone “except during stimulation” rather 

than focusing on maintaining the integrity of the confining zone, which is what really matters for 

protecting USDWs. Second, it fails to refer specifically to the full range of potential geomechanical 

failure modes potentially posed by operations at a particular site. Third, the type of geomechanical 

risk that is addressed (initiation or propagation of fractures), is dealt with in a potentially arbitrary 

fashion (the 90% of fracture pressure limit), which may not be appropriate in all cases. 

Our recommended language addresses these concerns by focusing on maintaining the integrity of 

the confining zone and including tensile failure and shear failure as transmissivity concerns. It calls 

for additional geomechanical studies of tensile failure and shear failure only “where appropriate” 

because there will be locations where experience or existing information will provide sufficient 

evidence to avoid the need for additional studies. The need for conducting additional tests and for 

determining which tests would be acceptable is left to the Director’s discretion. 

The owner or operator must comply with a maximum injection pressure limit 

approved by the Director and specified in the permit. In approving a maximum 

injection pressure limit, the Director shall consider the results of well tests and, 

where appropriate, geomechanical or other studies that assess the risks of tensile 

failure and shear failure. The Director shall approve limits that, with a reasonable 

degree of certainty, will avoid initiation or propagation of fractures in the confining 

zone or cause otherwise non-transmissive faults transecting the confining zone to 

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

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

Closure Standard

We believe there are three problems with the closure standard in proposed section 146.93(b). First, 

the presumption that monitoring should continue for 50 years is unnecessary and 

counterproductive. A straight performance standard is preferable to this or any other fixed time 

period because it provides a clearer standard and an incentive to maximize the understanding of site 

and project performance and as such is more protective of USDWs. Second, the proposal requires a 

showing that the CO2 plume has “stabilized”, which is undefined. Cessation of plume movement is 

not necessarily essential to show that a project poses no threat of endangerment to USDWs—

plumes that are still moving may, nonetheless, remain contained. Instead, it is more protective to 

show that the plume is not expected to encounter a leakage pathway. Third, the required showing 
Cynthia C. Dougherty 

December 23, 2008 

Page 4 

that “no additional monitoring is needed” does not provide guidance regarding how an operator is 

to show that no additional monitoring is needed. The proposal below provides specific guidance on 

what the operator must show. 

We recommend the standard in the proposed alternative language for section 146.93(b) below 

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

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

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

advantage of this approach is that it establishes clear criteria that an operator must demonstrate 

before obtaining site closure based upon particular site characteristics and is, therefore, reasonably 

applicable to any storage site as opposed to a standard based upon a fixed-duration. Furthermore, it 

is more stringent than a purely discretionary approach because it establishes specific criteria that 

must be shown before site closure may be granted. We believe this language, which is an extension 

of work done by the World Resources Institute and the Ground Water Protection Council, avoids 

the noted shortcomings and provides stronger protection for USDWs. 

146.93 (b) The owner or operator shall monitor the site following the cessation of 

injection. 

 (1) The owner or operator shall continue to conduct monitoring as specified 

in the Director-approved post-injection site care and site closure plan until closure is 

authorized pursuant to 146.93(b)(3). 

 (2) The owner or operator can request and demonstrate to the satisfaction of 

the Director that the post-injection site care and site closure plan should be revised 

to reduce the frequency of monitoring. 

 (3) Prior to authorization for site closure, the owner or operator must 

demonstrate to the Director, based on monitoring, other site-specific data, and 

modeling that is reasonably consistent with site performance, that no additional 

monitoring is needed to assure that the geologic sequestration project does not and is 

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

closure if the owner or operator demonstrates, based on the current understanding 

of the site, including monitoring data and/or modeling, all of the following: (i) the 

estimated magnitude and extent of the project footprint (CO2 plume and the area of 

elevated pressure) ; (ii) the estimated location of the detectable CO2 plume; (iii) that 

there is no significant leakage of either CO2 or displaced formation fluids that is 

endangering USDWs; (iv) that the injected or displaced fluids are not expected to 

migrate in the future in a manner that encounters a potential leakage pathway into a 

USDW; (v) that the injection wells at the site completed into or through the injection 

zone or confining zone are plugged and abandoned in accordance with these 
Cynthia C. Dougherty 

December 23, 2008 

Page 5 

requirements; and (vi) any remaining project monitoring wells at the site are being 

managed by a person and in a manner acceptable to the Director. 

Need for adequate implementation resources

Although not directly addressed in the EPA proposal, the need for adequate resources to implement 

the regulatory program for geologic sequestration at both the federal and state levels is a major 

consideration and one that EPA should be addressing both internally and in its discussions with 

Congress. The annual national budget for the UIC program (approximately $11 million) has 

remained static for many years, while UIC agencies have been asked to take on additional 

responsibilities. Furthermore, inflation of salaries and other expenses has eroded the buying power 

of the unchanging UIC budget. If state and regional agencies are asked to take on the additional 

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

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

If the nation is serious about controlling CO2 through underground injection, significant additional 

resources will need to be made available to hire new permitting staff and field inspectors. Those new 

staff, along with the existing cadre of UIC staff and managers, must be trained in subjects that will 

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

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

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

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

in the overall geologic sequestration effort. 

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

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

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

estimated that EPA will need to provide funding at a level of $100 million annually to meet the 

needs for the full UIC program, including the regulation of geologic sequestration. 

Conclusion

We greatly appreciate the extension of the public comment period, as it has allowed us to make 

substantial progress in expanding our shared understanding on the relevant issues and to reach 

significant agreement on how these issues can be addressed and resolved by EPA. The undersigned 

submit these recommendations with the request that the recommendations be considered as a whole 

because the recommendations were developed in combination to accurately reflect our shared 

understanding. In addition, we are committed to continuing our discussions and to inviting others 

to participate with an objective of developing additional specific recommendations for improvement 

of a final rule that could be adopted by your scheduled date in late 2010 or early 2011, including 

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

 

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

December 23, 2008 

Page 6 

not conducted in conjunction with enhanced oil and gas production operations. We will be working 

toward submission of additional recommendations by February 28, 2009.

Sincerely, 

Kyle Isakower 

Director, of Policy Analysis 

American Petroleum Institute 

Craig Walters 

General Manager, Enhanced Oil Recovery 

Anadarko Petroleum Corporation 

Brian Williams 

Global CO2 Storage Manager 

BP Alternative Energy North America Inc. 

Karen St. John 

Director Regulatory Affairs 

BP America Inc. 
Cynthia C. Dougherty 

December 23, 2008 

Page 7 

Robert F. Van Voorhees 

Counsel to the Carbon Sequestration Council (CCS Contact Group) 

Kurt Waltzer 

Carbon Storage Development Coordinator 

Clean Air Task Force 

Jeff W. Sheets 

Senior Vice President 

Planning & Strategy 

ConocoPhillips 

Ronald T. Evans 

Senior Vice President, Reservoir Engineering 

Denbury Resources Inc. 

William L. Fang 

Deputy General Counsel 

Edison Electric Institute 
Cynthia C. Dougherty 

December 23, 2008 

Page 8 

Scott Anderson 

Senior Policy Advisor, Climate and Air Program 

Environmental Defense Fund 

Michel Paque 

Executive Director 

Ground Water Protection Council 

Al Collins 

Senior Director, Regulatory Affairs 

Occidental Petroleum Corporation 

Karl R. Moor 

Vice President and Associate General Counsel 

Southern Company 

Darrick W. Eugene 

General Counsel 

Texas Carbon Capture & Storage Association 

cc: Ben Grumbles 

 Steve Heare 

 Ann Codrington 
Letter ID: 0190 

Commenter: Robert F. Van Voorhees 

Organization: Carbon Sequestration Council 

Letter ID: 0190 Comment ID: 24314 Letter Lines: 46 to 64 

Comment Code: 1000 1. General and Administrative Comments 

Comment: CSC has participated in the development of the multi-stakeholder discussion 

(MSD) process leading to the submission of a joint letter to EPA. We join the 

other participants in expressing our appreciation for EPA’s extension of the 

public comment period that allowed us to make substantial progress in expanding 

our shared understanding on the relevant issues and to reach significant 

agreement on how these issues can be addressed and resolved by EPA. CSC supports 

all of the recommendations presented in that letter, which are submitted with 

the request that the recommendations be considered as a whole because the 

recommendations were developed in combination to accurately reflect our shared 

understanding. 

In addition, we are committed to continuing the MSD process and to inviting 

others to participate with an objective of developing additional specific 

recommendations for improvement of a final rule that could be adopted by EPA’s 

scheduled date in late 2010 or early 2011, including development of the 

requirements to be applied to oil and gas reservoir geologic sequestration that 

is not conducted in conjunction with enhanced oil and gas production operations. 

We will be working with the other MSD participants toward submission of 

additional recommendations by February 28, 2009. 

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

responses to this letter and those of other participants of the MSD process for further details. For 

additional information on EPA's final regulatory approach, including involving the public in 

permitting decisions, please see the final rule and preamble as well as the rulemaking docket. 

Letter ID: 0190 Comment ID: 24315 Letter Lines: 78 to 84 

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

Comment: We strongly support EPA’s effort to develop appropriate regulations governing 

CO2 injection for purposes of GS. We agree that GS is an important option for 

the reduction of CO2 emissions, that the UIC program provides the appropriate 

framework for the regulation of CO2 injection, and that UIC regulations 

specifically tailored to CO2 injection could play a vital role in facilitating 

the development and implementation of GS projects while ensuring that 

appropriate environmental safeguards are in place. 

1
Individual Response: EPA agrees with the comment and believes that the creation of a new 

injection well class (VI) under the existing UIC Program is necessary to enable deployment of 

GS as a climate change mitigation technology in a manner that protects USDWs from 

endangerment. EPA agrees that the UIC Program, under the authority of the SDWA, provides a 

strong framework for regulating injection of CO2 for GS and adds that the GS regulation tailors 

the UIC requirements to address the unique issues associated with 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. 

Letter ID: 0190 Comment ID: 24316 Letter Lines: 86 to 106 

Comment Code: 1330 1.1.3.1 Support use of GS in general 

Comment: As EPA has correctly recognized, it is critical that any UIC program regulation 

addressing GS be designed to achieve two goals. First - obviously - such a rule 

should ensure that CO2 injection is conducted in a manner that is protective of 

human health and the environment. Second, such a rule should effectively 

facilitate the development of GS as a means for greenhouse gas (GHG) mitigation. 

EPA’s rulemaking effort will prove successful only to the extent that both of 

these goals are achieved. 

Fortunately, there is abundant evidence that CO2 injection can be accomplished 

in a manner that is protective of human health and the environment. Indeed there 

has been a long history of successful injection well operation in the United 

States, and multiple studies have confirmed that the UIC program has been 

remarkably effective in ensuring protection of human health and the environment. 

While GS projects are likely to be large in scale, it is important to recognize 

that the injection of CO2 is nothing new. To the contrary, CO2 has been injected 

for purposes of enhanced oil and gas recovery (EOR/EGR) for more than thirtyfive years, and the UIC program already regulates more than thirteen thousand 

CO2 injection wells that have successfully injected more than 600 million tons 

of CO2. Accordingly, there is a vast body of experience demonstrating that CO2 

injection can be conducted without adverse impacts on human health and the 

environment. 

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

responses to this letter 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: 0190 Comment ID: 24317 Letter Lines: 108 to 116 

Comment Code: 1600 1.3 Risk Associated with CO2 GS 

Comment: Unfortunately, the proposed rule does not seem to reflect an adequate 

2
appreciation of the demonstrated strength and experience of the UIC program. 

Instead the proposal appears to be based on an exaggerated assessment of the 

risks and challenges involved in CO2 injection; as a result the proposed rule 

would impose requirements that are substantially more elaborate, burdensome and 

prescriptive than necessary to protect human health and the environment. Because 

such requirements would impose regulatory burdens that are disproportionate to 

any environmental benefits they might provide, they would do more to impede and 

deter GS than to facilitate its responsible use. 

Individual Response: EPA acknowledges that industry has decades of experience with well 

construction and operation. For example, the oil and gas industry has experience drilling and 

cementing wells in very deep formations, in a variety of environments (e.g., high-pressure and 

low-pressure formations), and for a variety of uses (e.g., injection, oil and gas production, 

monitoring). EPA believes that this experience has led to the development of well materials and 

construction and operating procedures that are applicable to Class VI wells. 

EPA disagrees that the GS requirements are excessive or are based on an exaggerated assessment 

of risks and challenges involved in CO2 injection. The Agency believes that injecting large 

volumes of CO2 for GS poses unique challenges that, if not properly managed, could endanger 

drinking water sources or have other adverse impacts. EPA believes that caution is warranted 

and has, as a result, developed a new well class with requirements tailored to address the unique 

challenges posed by GS and potential risks associated with long-term injection of CO2. These 

requirements include the tailored AoR delineation process per §146.84, monitoring that is 

appropriate to GS projects per §146.90, and extended post-injection site care per §146.93. 

As part of its adaptive rulemaking approach, 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. 

EPA clarifies that the GS rule does not promote GS in specific settings, nor does it limit injection 

activities to any specific type of formation, geographic region, or depth. The focus of the GS rule 

is to ensure that, where GS is deployed, it is conducted in a manner that is protective of USDWs. 

Letter ID: 0190 Comment ID: 24318 Letter Lines: 118 to 126 

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

Comment: To achieve its goals for this rulemaking - to address the risks of CO2 injection 

and promote the development of GS - EPA must take a hard look at the need for, 

and practical utility of, each of the requirements it has proposed for CO2 

injection. As further detailed in these Comments, we believe that the proposed 

requirements can and should be streamlined significantly to increase the 

flexibility of the requirements for CO2 injection and reduce the unnecessary 

(and ultimately counterproductive) regulatory burdens the proposed rule would 

impose. We respectfully urge EPA to modify its proposed regulatory approach 

3
accordingly. 

Individual Response: The Agency believes that the Class VI requirements balance site-specific 

flexibility with USDW protection. Rather than setting performance or technology-based 

standards for GS projects, EPA is adopting a flexible approach where operators of GS projects 

would develop and implement site-specific plans for delineating the AoR, testing and monitoring 

the site, performing corrective action, and post-injection site care. EPA believes that the plans—

which would be reviewed and approved by the Director and periodically updated throughout the 

life of the project—promote an ongoing dialogue between the operator and the Director that will 

encourage use of the most appropriate technologies for a particular project. 

Letter ID: 0190 Comment ID: 24319 Letter Lines: 132 to 184 

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: We support EPA’s conclusion that the UIC program provides an appropriate 

framework for regulation of carbon dioxide (CO2) injection for geologic 

sequestration (GS). The UIC program governs a very wide range of underground 

injection activities - including the operation of thousands of existing CO2 

injection wells - and enjoys an extensively documented record of success. The 

program has in many respects been a model for Federal-State cooperation, and has 

benefited from a long history of regulatory and technical discourse among 

agencies and regulators armed with considerable practical experience and 

exceptional technical expertise. While the UIC program is focused on the 

protection of "underground sources of drinking water" (USDWs), this seemingly 

narrow objective is narrow in name only. In fact, the measures the UIC program 

relies upon to protect USDWs - measures designed to ensure that injected 

material remains isolated in the deep subsurface - are by nature sufficient to 

ensure protection of human health and the environment. 

The UIC program currently provides regulations that can be (and are being) 

successfully applied to CO2 injection into oil and gas reservoirs. We also agree 

that it makes sense to develop regulations more specifically designed to address 

CO2 injection in the GS context especially for formations that are not oil and 

gas reservoirs. Such regulations can and should be designed to build on relevant 

UIC program experience, including experience with CO2 injection, and should be 

tailored to address the particular needs for this category of injection 

activity: both the need to protect USDWs and the need to facilitate use of GS as 

a technology for reducing CO2 emissions. Those regulations should follow a 

flexible, performance-based approach that allows regulators to tailor specific 

permit requirements as appropriate based on the broad range of injection sites 

and practices that may be encountered in the GS context and on the body of 

knowledge and experience that will be gained not only from pilot and 

demonstration projects, but from the initial deployment of commercial scale 

geologic sequestration projects. 

4
Moreover, the safeguards of the UIC program have been adequate to protect USDWs 

of all types, including sole source aquifers, from injection that occurs 

substantially below those aquifers even where that involves drilling through the 

aquifer to construct wells that will inject into deeper formations. These 

drilling activities have not resulted in any significant contamination of sole 

source aquifers and, indeed, have probably served to protect those aquifers by 

avoiding surface disposal operations that would have been more likely to pose 

threats of endangerment to drinking water resources.[FN1] 

[FN1: Each year, industrial facilities and municipal wastewater treatment 

plants generate billions of gallons of hazardous and non-hazardous waste. Class 

I injection wells provide a safe means to remove these wastes from the surface 

environment by isolating them deep below the land surface, away from drinking 

water resources. 

Class I injection wells inject far below the lowermost USDW. Injection zones 

typically range from 1,700 to more than 10,000 feet in depth. The injection zone 

is separated from USDWs by an impermeable "cap" rock called the confining layer, 

along with additional layers of permeable and impermeable rock and sediment that 

separate the injection layer from the USDW. 

http://www.epa.gov/safewater/uic/wells_class1.html] 

Individual Response: EPA acknowledges the comment and believes that the creation of a new 

injection well class (VI) under the existing UIC Program is necessary to enable the use of GS as 

a climate change mitigation technology in a manner that protects USDWs from endangerment. 

EPA agrees that the UIC Program, under the authority of the SDWA, provides a strong 

framework for regulating injection of CO2 for GS and adds that the GS regulation tailors the 

UIC requirements to address the unique issues associated with 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. 

EPA agrees that the implementation of the GS rule in a manner that ensures protection of 

USDWs from endangerment is important to establishing a foundation for further advances in the 

field of CO2 GS. EPA acknowledges the need for regulatory certainty: the final GS requirements 

provide a level of certainty by setting forth unique requirements for GS. These requirements 

include: the tailored AoR delineation process at §146.84, the types of monitoring appropriate to 

GS projects at §146.90 and the post-injection site care process at §146.93. For additional 

information on these requirements, please also see the discussion of EPA’s Final Regulatory 

Approach in the preamble to the final GS rule. 

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 

5
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: 0190 Comment ID: 24320 Letter Lines: 186 to 274 

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: B. We Support Continued Application of the Class II Regulations to CO2 Injection 

in the Enhanced Oil or Gas Recovery Context and for GS in Oil and Gas Reservoirs 

and the Creation of "Class VI" Regulations to Address Most Other CO2 Injection 

Wells Used for GS. 

CO2 injection wells are currently permitted as Class II or Class V "experimental 

technology" wells. Under the proposed rule, Class II CO2 injection in 

conjunction with oil and gas production would remain under Class II, and a new 

classification - Class VI - would be created for GS. This approach makes sense 

except that all injection of CO2 in oil and gas reservoirs, including injection 

for GS, should remain in Class II to avoid circumstances where EOR operations 

might be compelled to shift back and forth between Class II and Class VI 

depending on market conditions. CO2 injection for purposes of enhanced oil or 

gas recovery ("EOR/EGR") has been successfully regulated as Class II injection 

for decades, and we agree with EPA that there is nothing to justify any 

disruption of the existing regulatory regime for the thousands of injection 

wells already in use in these operations. For other GS injection projects 

outside of oil and gas reservoirs, Class VI regulations would permit a more 

structured basis for regulation than the current Class V regulations. 

As EPA has recognized, the creation of a new well class does raise some 

applicability and transition issues. The key applicability issue relates to the 

distinction between Class II and Class VI when CO2 is injected for the purpose 

of GS in connection with EOR/EGR operations. EPA’s Proposal would continue to 

regulate and permit injection of CO2 for EOR/EGR purposes as Class II injection 

"as long as any production is occurring." EPA has asked for comment on the 

merits of this approach "since owners or operators of some Class II EOR/EGR 

wells may wish to use wells for the purposes of production and GS prior to the 

field being completely depleted." 73 Fed. Reg. at 43502. In fact, it is more 

than likely that CO2 will be injected both for purposes of EOR/EGR and GS. The 

rules should be clarified to be consistent with EPA’s intent, as we understand 

it, that where GS of CO2 occurs in connection with EOR/EGR activities the 

applicable class of wells and regulatory requirements is Class II. Furthermore, 

the UIC rules should provide a "bright line" standard for determining when 

EOR/EGR production activities cease and CO2 injection for GS continues. When 

6
EOR/EGR production activities cease and CO2 injection for purpose of GS 

continues, the risk profile changes, as further discussed below. This potential 

change in risk profile would necessitate additional requirements that are 

commensurate with both the historic EOR/EGR operations in the particular oil and 

gas field and with the risk profile of continued CO2 injection for GS. The MSD 

joint letter states that the Group has agreed that the wells used for GS in oil 

and gas reservoirs that do not meet the criteria of (b)(4) should be subject to 

additional requirements" and indicates further that the Group has "tentatively 

defined such wells as wells used ‘for geologic sequestration in oil and gas 

formations and where the criteria of paragraph (b)(4) are not met.’" There may 

be a further recommendation that EPA establish a Class II regulatory regime for 

continued injection of CO2 for GS when EOR/EGR production has been terminated 

based upon a "bright line" definition. These topics are discussed in further 

detail below. 

In the course of a typical EOR operation, even where there is no intent to 

sequester, 30-50% of the injected CO2 will remain in the reservoir after 

production operations cease. The balance is either dissolved within the produced 

oil or recycled for use in other reservoirs; it is not emitted to the 

atmosphere. Today approximately 90% of the CO2 used in enhanced recovery 

operations is produced from naturally occurring geologic accumulations. Rather 

than using this naturally occurring CO2, operators should be encouraged to 

mitigate greenhouse gas emissions by using anthropogenic CO2 instead. Oil and 

gas reservoirs have proved capable of containing water-buoyant fluids and gases 

for millions of years. These reservoirs are well studied and they offer the best 

opportunity to kick-start large-scale geologic storage of CO2 building on 100 

years of oil field operating experience. Accordingly, EOR/EGR operations using 

the same procedures now in place would result in sequestering anthropogenic CO2 

and should continue to be subject to the same requirements that have 

successfully protected USDWs since the inception of enhanced recovery 

operations. EPA should therefore clarify that EOR/EGR operations that include 

CO2 injection for the purpose of sequestration, or what is sometimes called "EOR 

with sequestration," will remain covered by Class II requirements. EPA 

recognition of EOR with anthropogenic CO2 as a valid form of geologic 

sequestration will provide much needed incentive for near-term geologic 

sequestration efforts, while longer-term cap and trade or taxation schemes 

develop. As long as oil or gas production continues, this remains an EOR/EGR 

operation and should remain in Class II. 

There are two different transition issues; the first of which involves the 

status of Class II CO2 injection wells after oil and gas recovery operations 

cease. In this situation, EPA should revise its proposal to retain the 

regulation of all GS in oil and gas reservoirs in Class II, subject to 

appropriate requirements as discussed below. Rather than require such wells to 

be permitted as Class VI wells - often by regulators in a different state agency 

than that authorized to administer the Class II program - this approach would 

7
leave permitting in the hands of the regulators with existing knowledge and 

expertise with respect to the oil and gas reservoirs and injection wells 

involved, thus leveraging regulatory resources and facilitating the seamless 

transition of oil and gas reservoirs to GS service following the completion of 

EOR/EGR operations. This approach would also reduce administrative complications 

or jurisdictional complexities that might otherwise arise and would provide 

additional regulatory flexibility in situations where production may stop and 

start in response to changing market conditions. 

Individual Response: The Agency disagrees that wells injecting CO2 for the primary purpose of 

long-term storage should be regulated under Class II requirements and has therefore developed 

new Class VI regulations to address the unique challenges and risks posed by this injection 

activity. The Agency tailored UIC requirements for Class VI wells that address the general risks 

deep injection may pose to USDWs and specifically address the unique nature of CO2 GS (i.e., 

very large volumes, very long time-periods, and reservoir pressure conditions). 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. 

EPA is developing guidance on transitioning permits from Class II to Class VI. The guidance 

will assist Directors in determining whether an injection project should be transitioned from 

Class II, where the primary purpose is oil and gas production, to Class VI, where the primary 

purpose is long-term storage of large volumes of CO2. The guidance describes recommended 

methods the Director may use to evaluate changes in risk to USDWs from projects, and how the 

Director may determine whether a project should be regulated within the Class II or Class VI 

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

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. For more information, please 

see the discussion on transition of Class II wells in the preamble to the final GS rule. 

In response to the comment on the burden of changing regulatory agencies in the middle of an 

operation, EPA clarifies that primacy is granted to a state, not to a specific agency within that 

state, and states may choose which agency will implement the Class VI program. States may, for 

example, choose an environmental quality protection agency (non-Class II) or the state's 

traditional oil and gas regulatory agency to implement the Class VI program as long as the 

program meets the minimum federal requirements for Class VI wells as required under section 

1422 of SDWA. Some states manage all injection well classes under Section 1422 and through a 

single agency, while in other states, Class II programs are run by oil and gas agencies. Some 

States allow their oil and gas agencies to regulate other well classes or subclasses provided they 

meet all federal requirements and are approved by the Agency. 

8
Regardless of the specific Agency the state selects to assume regulatory authority for Class VI 

operations, the state must obtain primacy for the 1422 Class VI program. Furthermore, the state 

may determine that a memorandum of understanding (MOU) between several state agencies 

regarding specific projects can facilitate this process without needing to change regulatory 

agencies after Class II projects have transitioned to a Class VI permit. 

Letter ID: 0190 Comment ID: 24321 Letter Lines: 276 to 317 

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 Code: 2064 1.5.3.2 Grandfathering construction of Class II wells (seeking comment) 

Comment: The other transition issue involves the substantive requirements that should 

apply to existing, currently-permitted wells that are converted to GS service. 

The preamble indicates that "the owner or operator would need to follow the 

permitting process outlined in today’s proposal to receive a Class VI permit," 

but EPA proposes "to give the Director discretion to carry over or ‘grandfather’ 

the construction requirements for existing wells if the Director makes a 

determination "that these wells would not endanger USDWs." 73 Fed. Reg. at 

43502. This approach seems backwards: having recognized the problems associated 

with the application of new well construction standards to existing wells, EPA 

should recognize that the well construction standards for all well classes are 

designed to ensure that USDWs are not endangered. Consequently, in the absence 

of some specific evidence of a construction problem that might endanger a USDW, 

there is no basis to question the construction of an existing, previouslypermitted injection well, and any "grandfathering" with respect to the Class VI 

construction requirements should be virtually automatic. 

In addition, it is important to recognize that the need and justification for 

"grandfathering" is not limited to construction requirements. There are also 

proposed Class VI operational and monitoring requirements that would require the 

substantial modification - if not outright abandonment - of many existing CO2 

injection wells (the proposed requirement for continuous monitoring of annulus 

pressure is a conspicuous example). In every case, the wells at issue have 

already been constructed consistent with requirements that UIC program officials 

have determined to be sufficient to prevent endangerment of USDWs. In view of 

this fact, there should be a regulatory presumption - absent some specific 

information to the contrary - that continued operation of wells already in CO2 

service for CO2 injection will also be protective of USDWs. 

The proposed Class VI regulations would require a relatively elaborate 

demonstration that injected CO2 will remain isolated from USDWs, and some 

supplementation of the permit requirements for existing wells may be appropriate 

consistent with the broad geological containment standards for Class VI wells. 

To the extent these or other supplemental requirements are truly necessary, they 

9
could and should be imposed through modification or supplementation of existing 

permit conditions rather than through the wholesale application of Class VI 

program requirements to pre-existing activities already found to be protective 

of USDWs. Accordingly, we recommend that the Final Rule include a presumption 

that wells already in CO2 service be allowed to transition to Class VI status-- 

or, in the case of Class II wells, to remain in Class II and be used for 

GS-based on their existing permit conditions, subject only to additional 

requirements as necessary to demonstrate geologic containment of the injected 

CO2 stream. 

Individual Response: EPA agrees that many Class II wells are designed and constructed to 

withstand exposure to CO2. Furthermore, the final GS rule allows 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 disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR 

requirements) should also be grandfathered from Class II wells. Following re-permitting of the 

well as Class VI, 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. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. 

EPA is developing guidance on transitioning permits from Class II to Class VI. The guidance 

will assist Directors in determining whether an injection project should be transitioned from 

Class II, where the primary purpose is oil and gas production, to Class VI, where the primary 

purpose is long-term storage of large volumes of CO2. The guidance describes the recommended 

methods the Director may use to evaluate changes in risk to USDWs from projects, and how the 

Director may determine whether a project should be regulated within the Class II or Class VI 

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

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. For more information, please 

see the discussion on transition of Class II wells in the preamble to the final GS rule. 

10
Letter ID: 0190 Comment ID: 24322 Letter Lines: 319 to 339 

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

USDW 

Comment: C. Class VI Injection Should Not be Limited to Injection Below the Lowermost 

USDW. 

The proposed rule limits Class VI injection to injection into formations that 

are below the lowermost underground source of drinking water (USDW). This 

requirement is not necessary for the protection of USDWs and would remove a 

substantial number of viable formations from consideration for GS. There are 

examples of existing CO2 injection wells (in the EOR/EGR context) that 

demonstrate that it is possible to inject CO2 above the lowermost USDW without 

causing any endangerment of USDWs. An excellent example is the Salt Creek EOR 

project in Wyoming, which has a USDW below the injection zone. The Wyoming State 

Geological Survey has already submitted comments emphasizing that restricting 

injection of CO2 only below the lowermost [SDW aquifer "will make it impossible 

to inject CO2 into deep saline aquifers in Rock Mountain Laramide [LARAMIE?] 

Basins (RMLB)." These comments go on to say: "For economic and regulatory 

purposes, the regulations as proposed will make geological sequestration of CO2 

impossible. To promulgate a geological CO2 sequestration regulation for RMLB out 

of the context of Rocky Mountain Laramide [?] geology will make it extremely 

difficult to mitigate the effects of greenhouse emissions on climate change in 

the West." Comments of Ronald Surdam, Director/State Geologist, Wyoming State 

Geological Survey (December 2008). 

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

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

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

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

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

final rule also establishes limited circumstances under which expansions of the areal extent of 

aquifer exemptions may be granted for owners or operators of Class II EOR/EGR wells 

transitioning to Class VI injection for GS. Additionally, the final GS rule does not categorically 

preclude or prohibit injection into any type of formation. 

EPA 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. 

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. 

11
Letter ID: 0190 Comment ID: 24323 Letter Lines: 341 to 360 

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

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: D. RCRA/CERCLA Applicability 

In light of the current uses and potential future uses of CO2 for EOR/EGR, EPA 

has taken a sensible approach by proposing to create a new Class VI well 

category based on the injection of the CO2 stream as fluid without 

characterizing that stream as a waste. It is neither necessary nor helpful to 

categorize CO2 as a pollutant or waste, and that would likely prove detrimental 

to technology development. Indeed, we are concerned that EPA’s brief discussion 

of a supposed potential for injected CO2 streams to be characterized as 

hazardous waste (or some type of hazardous release) are causing apprehension and 

could have a significant chilling effect on any future deployment of carbon 

capture and sequestration technologies. Through the work of our engineers and 

scientists with capture technologies and their extensive experience with the 

types of power plant flue gas likely to be sources of CO2 for sequestration, we 

do not believe that captured CO2 streams should trigger the application of 

either RCRA or CERCLA. Accordingly, we encourage EPA to dispel concerns that 

geologic sequestration could be encumbered with those requirements except 

possibly through the commingling of a captured CO2 stream with an actual waste 

stream, and we are not suggesting that such commingling should be permissible in 

the GS context. 

Individual Response: EPA thanks the commenter for their views on CCS, and notes that the GS 

rule is not promulgated under either the RCRA or CERCLA statutes, and further, the 

applicability of those statutes will not be determined under the SDWA or the terms of the GS 

rule, but rather according to those statutes themselves and any implementing regulations that 

may apply. 

EPA received many comments regarding the applicability of the RCRA regulations and statute to 

CO2 streams that are geologically sequestered under the final Class VI UIC well requirements. 

As a result, EPA has decided to initiate a separate proposed rulemaking specifically to examine 

the issue of RCRA applicability to CO2 streams being geologically sequestered, including the 

possible option of a conditional exemption from the RCRA requirements for CO2 GS in Class 

VI wells. EPA will consider these comments as part of its development of that proposal. The 

Agency will consider issues particular to RCRA in the context of that separate rulemaking, and 

recommends that the commenter read that proposed rule when it is published. The Agency notes 

that commenters who wish to submit comments on the RCRA proposal will need to do so during 

the comment period for that rule. Finally, EPA also notes that the final GS rule, which adds new 

regulations for Class VI wells under the Safe Drinking Water Act (SDWA), is not making any 

changes to the RCRA regulations. 

12
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” as defined in 

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

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

permit. 

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

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

USDWs from endangerment. 

Letter ID: 0190 Comment ID: 24324 Letter Lines: 362 to 418 

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

Comment: 1. RCRA Applicability 

EPA’s Proposal suggests that injected CO2 may be considered hazardous waste for 

RCRA purposes, and defines "carbon dioxide stream" to exclude hazardous waste. 

73 Fed. Reg. at 43503. The premise appears to be that CO2 is solid waste, and 

that a waste determination for such solid waste would turn on the specific 

composition of the CO2 in question. Id. Based on this premise, the preamble 

suggests that "EPA cannot make a categorical determination as to whether 

injected CO2 is hazardous waste under RCRA." Id. 

In fact, there are important categorical determinations that EPA can and should 

make with respect to the RCRA status of CO2. We urge EPA to make these 

determinations as follows. 

First, EPA should clarify that gas-phase CO2 is not solid or hazardous waste for 

RCRA purposes and is not subject to any RCRA waste determination requirements. 

The RCRA definition of "solid waste" does not include gaseous material unless it 

is "contained." RCRA 1004(27), 42 U.S.C. 6903(27). EPA has long taken the 

position that gasses do not qualify as "solid waste" under this definition 

unless they are "contained" in a cylinder or similar container. 54 Fed. Reg. 

50968 at 50970, 50973 (December 11, 1989). It follows that gas-phase CO2 streams 

are not solid waste, are not subject to the waste determination requirements of 

40 C.F.R. 262.11, and cannot be considered hazardous waste for RCRA purposes. 

Second, EPA should clarify that supercritical CO2 is not solid or hazardous 

waste for RCRA purposes and is not subject to any RCRA waste determination 

13
requirements. 

Again, the RCRA definition of solid waste is limited to "solid, liquid, semisolid, or contained gaseous material." RCRA 1004(27). Because supercritical CO2 

is none of these things; a plain reading of the statutory text suggests that 

supercritical CO2 should not be considered "solid waste." This reading of the 

statute makes sense, because RCRA is plainly aimed at the kind of material that 

could end up being dumped into a landfill. Uncontained supercritical CO2 is not 

such a material. Instead, the physical properties of supercritical CO2 are such 

that it would immediately vaporize - becoming an uncontained gas - before it 

could contribute to the contents of a landfill. A related practical 

consideration is the fact that the hazardous characteristics - the broad waste 

determination criteria that provide a primary means for determining when solid 

waste is hazardous waste - are based largely on test methods that are 

inapplicable to materials such as supercritical CO2. In particular, the toxicity 

characteristic depends on test methods that can only be applied to materials 

that are solids or liquids at standard temperatures and pressures. This is 

unsurprising, because the toxicity characteristic was designed to assess the 

threat waste would have in a municipal landfill disposal scenario, a scenario 

that - as already discussed - is inherently inapplicable to uncontained 

supercritical CO2. Accordingly, it makes no legal, policy, or practical sense to 

treat uncontained supercritical CO2 as "solid waste" for RCRA purposes. EPA 

should therefore confirm that uncontained supercritical CO2 is not "solid waste" 

and is not subject to RCRA waste determination requirements. 

It follows that a CO2 stream would only qualify as "solid waste" if it is 

actually in the form of a liquid (i.e., a liquid containing dissolved CO2). In 

such a case, the liquid would meet the statutory definition of "solid waste," 

the requirement to perform a RCRA waste determination would be triggered, and 

the familiar test methods for waste determinations could be applied. 

Individual Response: EPA thanks the commenter for their suggested clarifications on the 

applicability of RCRA to CO2 streams being geologically sequestered. As noted elsewhere, EPA 

received many comments regarding the applicability of the RCRA regulations and statute to CO2 

streams that are geologically sequestered under the final Class VI UIC well requirements. As a 

result, EPA has decided to initiate a separate proposed rulemaking specifically to examine the 

issue of RCRA applicability to CO2 streams being geologically sequestered, including the 

possible option of a conditional exemption from the RCRA requirements for CO2 GS in Class 

VI wells. EPA will consider these comments as part of its development of that proposal. The 

Agency will consider issues particular to RCRA in the context of that separate rulemaking, and 

recommends that the commenter read that proposed rule when it is published. The Agency notes 

that commenters who wish to submit comments on the RCRA proposal will need to do so during 

the comment period for that rule. Finally, EPA also notes that the final GS rule, which adds new 

regulations for Class VI wells under the Safe Drinking Water Act (SDWA), is not making any 

changes to the RCRA regulations. 

14
Letter ID: 0190 Comment ID: 24325 Letter Lines: 420 to 631 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: 2. CERCLA Applicability 

The proposed rule raises the specter of CERCLA liability arising out of CO2 

geologic sequestration (GS) projects. Specifically, in Section II.D. of the 

preamble, EPA notes several "potential USDW impacts," including the potential 

that the injected CO2 could (1) force native brines into USDWs; (2) contain 

impurities; or (3) cause naturally occurring or otherwise pre-existing chemicals 

to be mobilized within the injection zone, for example, via the formation of 

carbonic acid and its leaching effects. 73 Fed. Reg. 43492, 43497 (July 25, 

2008). EPA then goes so far as to suggest that "The migration of formation 

fluids containing mobilized contaminants could cause endangerment of USDWs." Id. 

EPA reiterates some of these concerns under preamble Section 2.J., under the 

heading "Is injected CO2 considered a hazardous substance under CERCLA?" 73 Fed. 

Reg. at 43503-04. EPA indicates that CO2, while not itself a CERCLA "hazardous 

substance," could contain hazardous substance impurities. EPA indicates further 

that "the CO2 stream could react with groundwater to produce listed hazardous 

substances such as sulfuric acid." 73 Fed. Reg. at 43504. (It is unclear whether 

the reference to groundwater means injection zone formation fluids or USDW 

formation fluids.) In short, the CERCLA liability concerns flagged by EPA arise 

out of two basic scenarios: (1) pre-existing hazardous substances, or hazardous 

substance impurities or reaction products moving into or within the injection 

zone; and (2) these hazardous substances (or displaced brines) migrating from 

the injection zone. 

EPA also states: 

CERCLA exempts from liability certain "federally permitted releases" 

including releases in compliance with a UIC permit under SDWA. 

Therefore, Class VI requirements and permits will need to be carefully 

structured to ensure that they do not "authorize" inappropriate 

hazardous releases. This would include clarifying if there are potential 

releases from the well which are outside the scope of the Class VI 

permit. 

73 Fed. Reg. at 43504. 

The first concern raised by EPA does not appear to pose a very serious concern 

because injection into a permitted injection does not constitute a release under 

CERCLA. EPA has issued some relevant guidance in the UIC context. Specifically, 

EPA has concluded that the emplacement of fluids into an injection zone through 

an authorized injection well does not constitute a "release" for purposes of 

15
RCRA or CERCLA. See 50 Fed. Reg. 28712 (July 15, 1985). EPA relied upon CERCLA’s 

definition of "release," which requires hazardous substances to make it into the 

"environment." Under EPA’s interpretation, UIC injection zones do not constitute 

the "environment," but rather the injection zone is essentially part of the 

injection well system. Id. at 28713. One of the key elements for CERCLA 

liability is a release (or threatened release) of hazardous substances. 

Therefore, at least with respect to hazardous substances remaining in the 

injection zone, one of the key elements for CERCLA liability would not be met, 

regardless of whether the hazardous substances were in the discharge stream, 

mobilized pre-existing substances, or in-situ reaction products. For 

clarification, EPA should reiterate this interpretation in the preamble to the 

final GS rule. 

Notwithstanding this interpretation, significant CERCLA liability concerns could 

remain with respect to any migration from the injection zone. While we are 

unaware of any attempt to date by EPA or another government agency or private 

party, to apply CERCLA to a UIC site in such a scenario, or any similar context, 

the mere possibility is a significant concern that should be addressed by EPA in 

order to avoid serious discouragement of development and investment in CO2 GS 

projects. EPA should clarify in the final regulations the so-called "federally 

permitted release" exemption from CERCLA liability for purposes of the UIC 

program, as referenced by EPA in the preamble to the GS proposal. 73 Fed. Reg. 

at 43504. The FPR exemption affects two separate CERCLA areas: (1) release 

reporting and (2) cleanup liability. The FPR exemption operates differently in 

each area, and is more accurately characterized as two separate exemptions. 

Under CERCLA’s release reporting provisions, certain releases of hazardous 

substances are subject to a one-time notification requirement, but FPRs are 

exempt: 

Any person in charge of a vessel or an offshore or an onshore facility 

shall, as soon as he has knowledge of any release (other than a 

federally permitted release) of a hazardous substance from such vessel 

or facility in quantities equal to or greater than those determined 

pursuant to CERCLA - Sec. 9602 of this title, immediately notify the 

National Response Center.... 

42 USC § 9603(a). FPR is in turn defined to include various types of 

releases/discharges authorized under any of several federal or delegated state 

regulatory programs including "(G) any injection of fluids authorized under 

Federal underground injection control programs or State programs submitted for 

Federal approval (and not disapproved by the Administrator of the Environmental 

Protection Agency) pursuant to part C of the Safe Drinking Water Act [42 U.S.C. 

300h et seq.] ... 42 USC § 9601(10) (emphasis added). To apply the FPR exemption 

in the release reporting context, the issue for UIC permittees would simply be 

whether the release at issue was an authorized injection of fluids. If so, the 

16
release would not have to be reported. The FPR for cleanup liability purposes is 

more complicated. 

CERCLA § 107(j) states: 

Recovery by any person (including the United States or any State or 

Indian tribe) for response costs or damages resulting from a federally 

permitted release shall be pursuant to existing law in lieu of this 

section. Nothing in this paragraph shall affect or modify in any way the 

obligations or liability of any person under any other provision of 

State or Federal law, including common law, for damages, injury, or loss 

resulting from a release of any hazardous substance or for removal or 

remedial action or the costs of removal or remedial action of such 

hazardous substance.... 

42 USC § 9607(j). First, it is important to understand that the FPR exemption 

from cleanup liability only forecloses a CERCLA action; otherwise-viable actions 

under other laws remain viable, and are not affected. An aggrieved party would 

be free to assert claims based on any number of other causes of action typically 

utilized in hazardous substance contamination cases, such as common law claims 

for trespass, nuisance, negligence, strict liability, or "toxic tort," or 

statutory claims arising under state groundwater protection or cleanup liability 

laws. 

More importantly, in comparison with the release reporting context, the FPR 

exemption from cleanup liability applies not to the FPR directly, but rather to 

"response costs or damages resulting from" the FPR. This parallels CERCLA’s 

liability imposing provisions, which require a release of hazardous substances 

from a facility "which causes the incurrence of response costs." This exemption 

is obviously broader than just the FPR itself in that any resulting costs are 

covered. In other words, the measure of the scope of the exemption for liability 

purposes is not limited to whether the release qualifies as a FPR, but rather 

whether the costs at issue result from the FPR. 

With respect to UIC wells, if the emplacement of fluids through a well is 

authorized by the permit, the resulting costs due to the various circumstances 

identified by EPA - in-situ reaction or mobilization, migration, etc. - remain 

ultimately the result of the FPR, and would be covered by the liability 

exemption. In other words, but for the authorized injection, the costs would not 

have been incurred. Therefore, the FPR exemption should apply to the scenarios 

identified by EPA in the preamble, with the exception of costs incurred due 

solely to unauthorized releases - i.e., releases resulting from unauthorized 

injection. 

The scope of the FPR exemption in the CERCLA cleanup liability context has been 

interpreted narrowly by some courts, but none of the cases involved UIC sites. 

17
In promulgating the final rule, EPA could provide a more reasoned analysis of 

the FPR exemption, and dispel any unwarranted concerns about CERCLA liability. 

EPA realized over 20 years ago that CERCLA’s FPR exemption needed additional 

clarification with respect to both release reporting and liability issues. EPA 

issued proposed rules in 1983 and 1988 that were never finalized. See 53 Fed. 

Reg. 27267 (July 19, 1988). Most of the attention, however, focused on the 

release reporting issues, rather then the cleanup liability issues. 54 Fed. Reg. 

29305, 29307 (July 11, 1989). EPA did observe in the preamble to the proposal 

that an "underground injection of hazardous substances permitted under an 

[authorized state or EPA program] is considered federally permitted for purposes 

of CERCLA notification." (53 Fed. Reg. at 27273). EPA did not find it necessary 

to propose any amendments to the UIC program regulations. 

Having raised these CERCLA issues in its proposal, EPA should take the present 

opportunity to provide a regulatory clarification of the existing exemption from 

CERCLA cleanup liability for UIC projects. EPA should clarify that the scope of 

"authorized injection of fluids" which defines the FPR exemption should be 

provided by the definition of CO2 stream, which should define the scope of the 

permitted injection to include: 

[Any] carbon dioxide that has been captured from any source, plus 

incidental associated substances derived from the source materials or a 

capture process, and any substances added to the stream to enable or 

improve the injection process. 

73 Fed. Reg. at 43535, proposed 40 CFR §146.81(d), definition of "Carbon dioxide 

stream" (with our proposed modifications). For further clarification, EPA could 

provide that only the injection under a Class VI permit of streams failing to 

meet this definition would fall outside the scope of the "authorized injection 

of fluids" unless expressly authorized for injection in the permit covering the 

well. EPA should also address CERCLA § 107(j) and provide an appropriate 

clarification of the broad array of potential response costs or damages it would 

consider to result from an authorized UIC project, e.g. costs to address the 

migration of impurities, mobilized pre-existing contaminants, or displaced 

brines. 

Although the risk of a CO2GS project giving rise to CERCLA liability is 

relatively low, raising the prospect of any potential for CERCLA liability may 

be so chilling as to significantly curtail efforts to develop CO2GS projects. 

CERCLA’s far-reaching liability web and the tremendous costs that can be imposed 

on parties potentially liable under CERCLA are now well-known. Also well-known 

is the reluctance of businesses and investors to support projects faced with a 

potential for liabilities of a CERCLA-scale. For example, the impacts of CERCLA 

on the commercial/industrial property market in the late 1980’s and early 1990’s 

were devastating to many urban centers. To avoid incurring CERCLA liability, 

property owners and prospective purchasers simply avoided deals involving 

18
properties with any potential hazardous substance contamination. This 

contributed to the so-called "brownfield" problem of unused or underutilized 

properties being shunned due to potential or actual contamination, and the 

associated CERCLA liability concerns. This in turn led to the expansion of 

development to previously undeveloped "greenfields" sites that, while less risky 

from a CERCLA perspective, raised their own array of concerns such as urban 

sprawl, infrastructure costs, etc. In response to the negative impacts of 

potential CERCLA liability, EPA and many states have gone to great lengths over 

the last ten years to alleviate liability concerns and encourage brownfield 

development projects. Similarly, EPA should recognize the significant chilling 

effect that CERCLA liability concerns would have on the development and 

deployment CO2GS projects, especially in this era of high volatility in the 

investment markets. EPA should use the opportunity in this rulemaking to 

alleviate unwarranted CERCLA liability concerns to the greatest extent possible. 

Even more troubling than the potential negative impact on the investment 

community is the threat of subjecting hundreds, thousands, and even more 

numerous pore space owners to CERCLA liability. Their property interests in 

potential deep subsurface CO2GS project injection zones could subject them to 

strict, joint, and several liability under CERCLA pursuant to liability theories 

that could be conjured up by future litigants seeking compensation for 

investigation response - and possibly remediation - costs claimed to be incurred 

as a result of releases from geologic sequestration injection zones. The 

discussion of what might be required to acquire any necessary rights to conduct 

CO2GS projects is complex enough already without even beginning to consider how 

the willingness of pore space owners to participate might be obliterated by the 

uncertainties of CERCLA liabilities hanging over their heads. 

In short, EPA needs to seize the opportunity to dispel the specter of CERCLA 

liability raised in its preamble by developing appropriate language to provide 

the clarity and assurance needed to promote continued research, development and 

deployment of CO2GS projects. 

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

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

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

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

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

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

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

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

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

the scope of the Class VI permit. 

Furthermore, EPA is promulgating the GS rule under the authority of the SDWA. To the extent 

the commenter is seeking interpretations of CERCLA and its related provisions, such as the 

19
definition of a federally permitted release, such interpretations are beyond the scope of this 

rulemaking. 

The UIC program Director has authority under SDWA §1423 to address potential compliance 

issues (e.g., potential releases that may endanger USDWs) resulting from injection violations in 

the unlikely event that a remedial response is necessary. Although EPA anticipates that the need 

for emergency or remedial actions at GS sites will be rare, the GS rule requires, at §146.94, that 

emergency and remedial response plans be developed and updated to address such events and 

that owners or operators demonstrate that financial resources are set aside to implement the plans 

if necessary, per §146.85. 

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

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

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

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

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

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

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

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

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

operator when approving site closure. 

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

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

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

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

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

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

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

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

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

which such violation occurs or failure to comply continues. 

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

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

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

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

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

EPA's final approach. 

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

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

USDWs from endangerment. 

Letter ID: 0190 Comment ID: 24326 Letter Lines: 633 to 690 

20
Comment Code: 1200 1.1 General comments about the rulemaking 

Comment Code: 1600 1.3 Risk Associated with CO2 GS 

Comment: E. EPA Should Ensure that the Regulations for GS Are Not More Stringent or 

Prescriptive than Necessary to Protect USDWs. 

EPA has recognized that it has two goals for the proposed rules for geologic 

storage of carbon dioxide: the protection of underground sources of drinking 

water [FN2/] and the promotion of the development of carbon capture and 

storage.[FN3/] EPA Administrator Stephen Johnson noted when he announced the 

proposal that ""[t]oday's proposal paves the way for technologies that would 

protect public health and help reduce the effects of climate change. With proper 

site selection and management, geologic sequestration could play a major role in 

reducing emissions of carbon dioxide into the atmosphere."[FN4/] We urge EPA to 

keep both of these goals in mind and to work to ensure that the regulatory 

regime that is ultimately adopted is designed to facilitate - not delay or 

discourage - the successful commercial-scale development of carbon capture and 

storage. The potential emissions benefits of commercial-scale carbon storage are 

too large and too important to ignore in the context of these regulations. 

[FN2/: 73 Fed. Reg 43492 (July 25, 2008) ("It proposes a new class of well and 

minimum technical criteria for the geologic site characterization, fluid 

movement, area of review (AoR) and corrective action, well construction, 

operation, mechanical integrity testing, monitoring, well plugging, postinjection site care, and site closure for the purposes of protecting underground 

sources of drinking water (USDWs).").] 

[FN3/: EPA Press Release, "EPA Lays Groundwork for Promising Technologies to 

Help Mitigate Climate Change" (July 15, 2008), 

http://www.epa.gov/safewater/uic/wells_sequestration.html ("EPA is proposing a 

rule that supports promising technologies to prevent industrial emissions of 

carbon dioxide. Secure, long-term underground storage of the greenhouse gas is 

one way scientific innovation could lessen the effects of climate change. . . . 

Carbon capture and storage is part of a portfolio of technologies available to 

reduce greenhouse gas emissions. EPA is coordinating with the Department of 

Energy on carbon sequestration research and development."); EPA Press Release, 

"EPA To Develop Regulations for Geologic Sequestration of Carbon Dioxide" 

(October 7, 2007) Id.] 

[FN4/: EPA Press Release (July 15, 2008).] 

Unfortunately, in its effort to ensure protection of USDWs, EPA has exhibited a 

zeal that could materially impede, overburden, and effectively stigmatize GS. 

The preamble to the proposed rule repeatedly overstates the risks posed by CO2 

injection while systematically understating the extent of knowledge and 

experience industry and regulators have gained through decades of practical 

experience with a wide range of injection well operations. As a result, the 

preamble presents an exhaustive review of every imaginable risk with respect to 

21
CO2 injection, but fails to disclose that many of these theoretical risks relate 

to implausible scenarios or concerns that - based on decades of robust 

operational and regulatory experience - are well understood and relatively easy 

to address. The scale of GS operations will certainly be larger than many 

previous CO2 injection operations, but it is not as though we do not have 

extensive experience with CO2 injection or that there is any fundamental lack of 

understanding about what happens when CO2 is injected underground. After all, 

there are already thousands of existing CO2 injection wells in operation that 

have injected hundreds of millions of tons of CO2 largely without incident. 

Rather than provide appropriate context for the development of Class VI 

regulations, however, the proposed rule gives the impression that GS is an 

adventure into entirely uncharted seas. The proposed rule - having started by 

framing the issues in this way - then employs a regulatory approach that errs on 

the side of including excessively prescriptive, overly-burdensome, and often 

redundant requirements. 

Individual Response: EPA disagrees that the GS requirements are excessive. The Agency 

believes that injecting large volumes of CO2 for GS poses unique challenges that, if not properly 

managed, could endanger drinking water sources or have other adverse impacts. EPA believes 

that caution is warranted and has, as a result, developed a new well class with requirements 

tailored to address the unique challenges posed by GS and potential risks associated with longterm injection of CO2. These requirements include the tailored AoR delineation process per 

§146.84, monitoring that is appropriate to GS projects per §146.90, and extended post-injection 

site care per §146.93. 

EPA acknowledges that industry has decades of experience with well construction and operation. 

For example, the oil and gas industry has experience drilling and cementing wells in very deep 

formations, in a variety of environments (e.g., high-pressure and low-pressure formations), and 

for a variety of uses (e.g., injection, oil and gas production, monitoring). EPA believes that this 

experience has led to the development of well materials and construction and operating 

procedures that are applicable to Class VI wells. 

As part of its adaptive rulemaking approach, 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. 

EPA clarifies that the GS rule does not promote GS in specific settings, nor does it limit injection 

activities to any specific type of formation, geographic region, or depth. The focus of the GS rule 

is to ensure that, where GS is deployed, it is conducted in a manner that is protective of USDWs. 

Letter ID: 0190 Comment ID: 24327 Letter Lines: 692 to 735 

Comment Code: 1200 1.1 General comments about the rulemaking 

Comment Code: 1600 1.3 Risk Associated with CO2 GS 

22
Comment: 1. The Proposed Class VI Requirements Are Far More Burdensome than Necessary 

to 

Protect USDWs. 

As the preamble acknowledges, the actual human health and ecological risks 

associated with GS are relatively remote and can be addressed effectively 

through measures implemented to protect USDWs. 73 Fed. Reg. at 43497-98. 

Unfortunately, having started with an exaggerated sense of the risks involved 

and an inadequate recognition of the value of existing regulatory and 

operational experience relevant to CO2 injection, the proposed rule seems to 

proceed from the premise that the most strict UIC regulations in existence - 

those for hazardous waste injection - should serve as the starting point for the 

development of the Class VI regulations. This is not a logical or appropriate 

regulatory approach, because CO2 - which is found in abundance both in ambient 

air and in the subsurface - is nothing like hazardous waste and plainly does not 

warrant the same level of regulation. In fact, the principal issues with respect 

to CO2 injection for GS relate primarily to the mobility of CO2 and the sheer 

magnitude of the injection operations involved; these are not issues that the 

requirements for hazardous waste injection are particularly well suited to 

address. 

The more logical starting point for development of the Class VI regulations is 

the Class II regulations. As the proposed rule recognizes, CO2 injection 

operations have been conducted pursuant to the Class II regulations for many 

years, and experience with thousands of wells injecting hundreds of millions of 

tons of CO2 demonstrates that the Class II regulations - as applied to CO2 

injection - are adequate to protect USDWs. This is certainly true with respect 

to the basic construction, operating, monitoring, and mechanical integrity 

testing requirements for injection wells; after all, what "works" in terms of 

the construction and operation of a CO2 injection well does not depend on the 

purpose for which CO2 is being injected. Accordingly, there is no reason why the 

Class VI requirements addressing issues such as well construction and mechanical 

integrity testing should be any different than the Class II requirements. 

Unfortunately, the proposed Class VI requirements are far more stringent than 

the Class II requirements, a fact that creates a need to "grandfather" Class II 

CO2 injection wells that remain in service for GS purposes after EOR/EGR 

operations cease. Rather than resembling the Class II requirements, the proposed 

Class VI requirements are as stringent as those for hazardous waste injection in 

most respects. Indeed, many of the construction, mechanical integrity, 

monitoring and financial assurance requirements proposed for Class VI wells are 

even more comprehensive and more strict than those for hazardous waste injection 

wells. While some of these more burdensome requirements are legitimately related 

to concerns about the mobility of CO2 or the anticipated scale of GS operations, 

many - as discussed in Part III of these comments - are not. 

23
Individual Response: EPA disagrees that the GS requirements are excessive or are based on 

exaggerated risks; the Agency believes that injecting large volumes of CO2 for GS poses unique 

challenges that, if not properly managed, could endanger drinking water sources or have other 

adverse impacts. EPA believes that caution is warranted and has, as a result, developed a new 

well class with requirements tailored to address the unique challenges posed by GS and potential 

risks associated with long-term injection of CO2. These requirements include the tailored AoR 

delineation process per §146.84, monitoring that is appropriate to GS projects per §146.90, and 

extended post-injection site care per §146.93. 

EPA believes that the nature of CO2 injection for long-term storage is different from Class II 

CO2 injection for ER, and that tailored requirements for Class VI wells are appropriate and 

necessary to protect USDWs from endangerment. For this reason, the Agency tailored UIC 

requirements for Class VI wells that address the general risks deep injection may pose to 

USDWs and specifically address the unique nature of CO2 GS (i.e., very large volumes, very 

long time-periods, and reservoir pressure conditions). 

Letter ID: 0190 Comment ID: 24328 Letter Lines: 737 to 785 

Comment Code: 1200 1.1 General comments about the rulemaking 

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

Comment: 2. Rules that Stigmatize GS or Burden it Excessively Would Not be in the Public 

Interest. 

The magnitude of the regulatory burdens imposed by the proposed Class VI 

requirements are of concern for several reasons. First, unnecessary regulatory 

burdens would act as a direct impediment and disincentive to the development of 

GS projects. Less directly, the imposition of unreasonably stringent regulatory 

requirements - particularly requirements for multiple layers of requirements 

addressing the same basic risks - inherently magnify the impression of risk and 

could thus stigmatize GS and discourage investment in GS projects. EPA should 

recognize that "more regulation" - particularly the "belt-and-suspenders plus 

more belts and more suspenders" approach reflected in the proposed rule - is not 

"better regulation" in the GS context. To the contrary, overly-burdensome 

regulation - to the extent it effectively impedes or deters use of a promising 

technology - could prove counterproductive. 

We understand the importance of public perception when it comes to the siting 

and permitting of needed infrastructure, and believe strongly in the need to 

ensure that the public has accurate information. To facilitate the public’s 

appreciation of the merits of GS, we urge EPA to ensure that it does not 

overstate the risks associated with CO2 injection or understate the justified 

confidence with which many potential issues and concerns can be addressed. 

Similarly, we urge EPA to avoid the imposition of regulatory requirements that 

are so disproportionate to the risks involved that they may do more to incite 

than address public concerns. To this end, EPA should scale back its regulatory 

24
requirements to more accurately reflect the magnitude of actual risks and to 

ensure that any requirements imposed are truly necessary for the protection of 

USDWs. 

EPA should also consider the effect its regulations might have on the ability to 

secure critical financial backing for GS projects. Any exaggerated impression of 

the risks involved in GS could adversely influence financial institutions and 

impede efforts to obtain financing. The recent turmoil in the financial markets 

highlights how challenging the financing of new technologies may become. In a 

credit-constrained world, investors will be wary of putting their limited funds 

behind GS projects if they believe they are likely to endanger the environment 

or public health. Accordingly, EPA should recognize the importance of the 

messages that it sends the financial world through the regulations it imposes. 

Permanent storage of CO2 can be accomplished safely and without harm to the 

environment as long as we apply the right knowledge base, detailed site-specific 

information, technical expertise, and sound management practices. However, we 

cannot implement an effective regulatory program for sequestering CO2 if the 

rules are based on the erroneous premise that CO2 represents an extreme hazard. 

It is therefore important that EPA send accurate messages about the nature of 

CO2 and the actual magnitude of the risks associated with GS. It is also 

critical that EPA strike an appropriate balance by addressing the risks 

associated with GS without creating a regime that effectively hinders or deters 

use of this key technology for reduction of carbon emissions. 

Individual Response: EPA disagrees that the GS regulation overstates the risk of CO2 injection. 

EPA recognizes that injecting large volumes of CO2 for GS poses unique challenges that, if not 

properly managed, could endanger drinking water sources and have other adverse impacts. 

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

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

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

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

prevent leakage from injection formations and protect USDWs. 

EPA does not believe that the tailored requirements will create a negative public perception of 

GS. The Agency believes that a demonstration to the public that GS projects are meeting the GS 

rule's tailored requirements will likely improve confidence in the project and help address public 

questions and concerns. 

Regarding the ability of owners or operators to secure financial backing for GS projects, EPA 

believes that, like the public, financing entities will have improved confidence in projects that 

incorporate multiple protective requirements. Please see the discussion of financial responsibility 

in the preamble to the final GS rule. 

Letter ID: 0190 Comment ID: 24329 Letter Lines: 787 to 818 

25
Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment: III. Comments Regarding Proposed Class VI Requirements 

A. Geologic Siting Requirements 

In view of the need to promote appropriate use of GS to reduce CO2 emissions, 

the regulations should be designed to allow GS in any geologic setting in which 

the Director concludes that GS can be conducted without endangering USDWs. It 

follows that the regulations should give the Director discretion to apply the 

"non-endangerment" performance standard on a site-specific basis as particular 

geologic site conditions warrant, without the need to apply prescriptive 

criteria that - while perhaps necessary to endure protection of USDWs in some 

cases - would arbitrarily disqualify some sites that would in fact be 

appropriate for GS. This does not mean that regulation need be lax; it simply 

means that regulation must be flexible, and that rigid criteria should not 

substitute for performance-based standards and site-specific consideration of 

the merits. 

The preamble to the proposed rule outlines normal site selection criteria for 

injection well projects, including the need to identify an injection zone with 

sufficient permeability, porosity, thickness and lateral extent and a lowpermeability confining zone with sufficient thickness and lateral extent to 

protect overlying USDWs. 73 Fed. Reg. at 43505. These are familiar and 

appropriate geologic siting requirements for injection well operations, and the 

regulatory text proposed for codification at 40 C.F.R. 146.83(a) - with 

relatively minor technical changes - would embody them appropriately. 

Unfortunately, the preamble goes on to suggest the need for overly-elaborate 

analysis of extraneous issues, and the rule text proposed for codification at 40 

C.F.R. 146.83(b) would allow the Director apparently unlimited discretion to 

impose siting conditions that go beyond those necessary to ensure protection of 

USDWs. EPA should clarify that site evaluation should go no farther than 

necessary to prevent endangerment, and should eliminate any apparent discretion 

to impose siting requirements that are not necessary to protect USDWs. 

Individual Response: The final rule does not preclude injection into any formations or types of 

injection sites provided that the wells meet the final GS rule requirements. The purpose of the 

GS regulation is to ensure that injection of CO2 for GS is conducted in a manner that is 

protective of USDWs. This includes appropriate site characterization and identification of 

geologic formations that are amenable to injection of potentially large volumes of CO2 for longterm storage. The regulation provides flexibility to owners or operators to select appropriate sites 

and target formations (under §146.82), well construction specifics (under §146.86), and injection 

procedures provided the owner or operator can demonstrate that the injection and storage will not 

endanger USDWs and that minimum requirements for the site are met. 

26
Letter ID: 0190 Comment ID: 24330 Letter Lines: 820 to 847 

Comment Code: 3110 2.1.1 Proposed siting requirements (i.e., injection/confining zones, 

trapping mechanism) 

Comment Code: 3140 2.1.4 Comments that the proposed geologic data requirements are too 

stringent 

Comment: 1. Site Evaluation 

The preamble appears to suggest the need for an elaborate evaluation of site 

conditions to address concerns related to seismicity and potential geochemical 

interactions. In fact, however, seismicity and geochemical impacts are issues 

that are easily addressed in the GS context, and requirements for unnecessarily 

elaborate analysis would serve only to burden and impede the development of GS 

projects. 

Concerns with respect to seismicity are frequently raised in the injection well 

context, but there is ample experience demonstrating that such risks are modest 

and easily addressed through appropriate injection pressure limitations. 

Similarly, geologic compatibility - while it can present issues in some contexts 

- is unlikely to present any serious problems in the GS context. These 

conclusions are confirmed by decades of experience with literally thousands 

Class II CO2 injection wells injecting hundreds of millions of tons of CO2. 

The apparent extent of concern about geochemical compatibility is particularly 

hard to understand. Although it is true that injection of CO2 can be expected to 

lead to the formation of carbonic acid, the resulting carbonic acid is only 

weakly corrosive and - as experience with the injection of extremely corrosive 

hazardous wastes demonstrates - cannot reasonably be expected to cause any 

breach of containment that would endanger a USDW. The proposed rule expresses 

specific concern about geochemical reactions that could alter the composition of 

the injected CO2 stream - particularly through the mobilization of contaminants 

that occur naturally in the injection zone - but such concerns are essentially 

immaterial because the specific composition of the CO2 stream matters little as 

long as the CO2 stream remains confined. 

Individual Response: The Agency believes that the site characterization requirements at 

§146.82 are essential to proper siting of a GS well and are the foundation for a detailed 

understanding of the local and regional geology. Collecting and evaluating geochemical data in 

and around the CO2 injection zone, as required in §146.82(a)(6), serves several purposes. This 

baseline geochemical data can help predict geochemical reactions between the injectate, 

reservoir geology, and formation fluids. Such reactions can lead to dissolution and precipitation 

of minerals which affect formation porosity, which in turn can affect required injection pressure 

(Sminchak and Gupta, 2002) and transport of fluid within the formation. While the confining 

layer is the primary barrier to CO2 movement into a USDW, multiple barriers are important and 

changes in injection pressure and fluid movement may compromise those barriers. An increase in 

27
injection pressure due to reduced porosity, in particular, can lead to fracturing of the confining 

layer and potentially allow fluid movement outside of the injection zone. Losses in injectivity 

because of geochemical reactions may also require additional injection wells and further 

penetrations in the confining layer that can become pathways for fluid migration. 

EPA disagrees with the comment that the composition of the CO2 stream is not important. 

Information about the composition of the CO2 stream informs decisions about the appropriate 

design and construction of the well, the potential for adverse mineral reactions in the subsurface 

geologic formations, and appropriate testing and monitoring parameters. 

EPA disagrees that injectivity is not an important consideration. While increasing storage 

capacity is not the intent of the UIC requirements, EPA believes that maximizing the amount of 

CO2 that can be injected through a single well may reduce the need for additional injection 

wells, which reduce the potential for unacceptable fluid movement and improve USDW 

protection from endangerment. 

Finally, EPA disagrees that consideration of local and regional seismicity is not important. The 

site characterization provisions in the GS rule, including a review of the local and regional 

geology, and detailed review of any known or potential seismically active terrain in the vicinity 

of a proposed GS site are necessary to minimize the potential for induced seismic events or the 

reactivation of faults, which are a known potential risk associated with injection and are 

addressed in all aspects of the UIC regulations. 

Letter ID: 0190 Comment ID: 24331 Letter Lines: 849 to 893 

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

(seeking comment) 

Comment: 2. Redundant Confining/Containment Zone Requirement 

EPA requests comment on whether the Final Rule should require, or allow the 

Director discretion to require, additional confining and containment zones above 

the primary confining zone. 73 Fed. Reg. at 43505-06. We oppose any such 

requirement. 

If there are substantial doubts as to the adequacy of a single confining 

formation, it would of course be necessary to specify one or more additional 

formations as part of the a confining system that would be adequate to protect 

USDWs; this is one of the reasons the term "confining zone" is defined in the 

way it is (i.e., to include a "geologic formation [or] group of formations" 

acting as a barrier to fluid movement). Considerations as to the adequacy of the 

confining zone are a central focus of the permitting process, with permit 

applicants being required to demonstrate that USDWs will not be endangered by 

the proposed injection activity. By definition, a requirement for additional 

confining zones would therefore be a requirement for redundant geologic 

28
containment: it would never be necessary for the protection of USDWs. By 

allowing the Director discretion to impose such a requirement, the proposed rule 

would expressly authorize the imposition of requirements that are not necessary 

for the protection of USDWs. Worse, the proposed rule provides no apparent limit 

on the Director’s discretion in this regard. Indeed, the preamble suggests that 

the Director could require detailed evaluation of additional geologic formations 

just because they are there, perhaps in the hope that additional study and 

documentation - though not necessary to show that USDWs will be protected - 

might "improve public confidence in and acceptance of" GS. 73 Fed. Reg. at 

43506. 

Again, the ultimate standard for geologic citing should be protection of USDWs. 

By authorizing extraneous siting (or site assessment) requirements that are not 

necessary for protection of USDWs, the proposed rule would invite a "belt and 

suspenders" approach that would unnecessarily burden permit applicants and 

signal unwarranted concern about the risks and uncertainties associated with CO2 

injection. Under the UIC program, protection of USDWs is and should be enough. 

The Director should have no discretion - let alone unlimited discretion - to 

"tack on" additional siting requirements. 

It should be noted that a requirement for redundant confining and containment 

zones would be unprecedented. No such requirement exists in the UIC program, 

even in the context of hazardous waste injection. Nor does such a requirement 

apply in any of the countries where GS projects are currently underway 

(including Norway, Canada, Australia and Algeria). EPA should not single out GS 

for heightened and substantially more rigorous requirements than would apply in 

other contexts. To do so would signal a disproportionate concern about the 

injection of CO2 that simply is not warranted on the merits. 

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. While other countries may not require such 

additional protection, EPA believes that providing the Director this additional discretion is an 

important element of assuring that GS activities will not endanger USDWs. 

Letter ID: 0190 Comment ID: 24333 Letter Lines: 895 to 906 

29
Comment Code: 3310 2.2.1.1 Comments in favor of requiring computational models to 

delineate the AoR (seeking comment) 

Comment: B. Area of Review and Corrective Action Requirements 

We support the use of computational models for determination of the appropriate 

area of review ("AOR") for GS purposes. Modeling of the pressure effects 

associated with injection - together with conservative modeling to bound the 

potential extent of CO2 plume movement - are appropriate aids to the evaluation 

of geologic siting and corrective action to address risks presented by 

artificial penetrations such as abandoned boreholes. The use of such modeling is 

already well-established in the context of oil and gas exploration and 

production and has been used in the UIC program for "no-migration" petitions for 

hazardous waste injection. Similar modeling can reasonably be adopted for use in 

the GS context as well. 

Individual Response: EPA acknowledges the commenter’s support and agrees that predicting 

the complex, multiphase, buoyant flow of the CO2, co-injectates, and compounds that may be 

mobilized due to injection requires the sophistication of computational models, as required at 

§146.84(c)(1). 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. 

Letter ID: 0190 Comment ID: 24334 Letter Lines: 908 to 947 

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

Comment Code: 3310 2.2.1.1 Comments in favor of requiring computational models to 

delineate the AoR (seeking comment) 

Comment: 1. AOR Definition 

The proposed rule vaguely defines the AOR as "the region surrounding" the GS 

project that "may be impacted by the injection activity." 72 Fed. Reg. at 43535 

(proposed 40 C.F.R. 146.81(d)). The definition goes on to suggest that the AOR 

is to be "based on computational modeling that accounts for the physical and 

chemical properties of all phases of the injected carbon dioxide stream." Id. 

There are three issues. 

First, the proposed definition suggests the need for a more complex modeling 

approach than may typically be necessary or appropriate. As experience with 

hazardous waste injection "no migration" petitions shows, it is rarely necessary 

to attempt to model chemical changes in the injectate plume; instead 

conservative modeling of transport should typically be sufficient by itself to 

30
show that USDWs will not be endangered. Where this is the case, it is 

containment of the injectate plume - rather than the precise composition of the 

plume - that matters and there is no need to model chemical changes. This is a 

critical point, because it is generally far easier to model transport than 

chemical changes occurring in the subsurface. In fact, it would be 

extraordinarily burdensome to have to model "the chemical properties of all 

phases of the injected carbon dioxide stream" as the proposed rule suggests. 

Such modeling should be required only to the extent that it is truly necessary 

to ensure that USDWs will be protected. 

Second, the preamble to the proposal suggests that the "best" (most 

sophisticated?) and most "accurate" modeling should be preferred or even 

required. 73 Fed. Reg. at 43507. However, fine precision generally isn't 

necessary, The appropriate goal for modeling is to ensure protection of USDWs, 

and conservative (i.e., less precise) modeling may be sufficient and even 

preferable for this purpose. A quest for greater precision would not guarantee 

greater confidence in modeling results, and could effectively require a less 

conservative - and thus potentially less protective - modeling approach. 

Third, the functional purpose of the AOR is to define the area within which 

impacts of the injection activity could cause endangerment of a USDW; 

specifically, the AOR defines the area within which corrective action for 

abandoned boreholes may be necessary to prevent endangerment of USDWs. The 

language of the proposed rule (i.e., "may be impacted by the injection 

activity") is not clearly limited to impacts of the injection activity that 

could cause endangerment of USDW’s. It should be. 

Individual Response: EPA believes that predicting the complex, multiphase, buoyant flow of 

the CO2, co-injectates, and compounds that may be mobilized due to injection requires the 

sophistication of computational models, as required at 146.84(c)(1). 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 sitespecific and predicted operating conditions as well as geologic heterogeneities and potential 

migration through faults, fractures, and artificial penetrations. 

EPA acknowledges that fine precision may not always be necessary and that many factors 

determine ultimate confidence in modeling results. However, EPA does not believe that more 

precision would result in a less protective modeling approach. EPA anticipates that the owner or 

operator, in consultation with the Director, will choose the model that is most appropriate for a 

particular GS project, and that this dialogue is a key factor in assuring that the GS site is modeled 

(and eventually operated and tracked) in a manner that protects USDWs from endangerment. 

EPA encourages and expects owners or operators to use the best multiphase, computational 

models available. 

31
Letter ID: 0190 Comment ID: 24335 Letter Lines: 949 to 956 

Comment Code: 3630 2.2.4.1 Comments in favor of allowing phased corrective action 

Comment: 2. Corrective Action 

Corrective action is a familiar UIC program requirement. Given the potential 

scale of GS operations, EPA has proposed requirements for a corrective action 

plan contemplating a phased implementation of corrective action. In general, 

this approach is prudent and practical, providing a rigorous approach to 

corrective action while reducing regulatory burdens by permitting a phased 

implementation of corrective action requirements. 

Individual Response: EPA acknowledges the commenter’s support of phased corrective action 

and agrees that phased corrective action may provide many benefits to a project including, but 

not limited to, spreading the burden of cost, avoiding delays in project start-up, allowing for use 

of future, improved corrective action techniques, and addressing unanticipated changes in the 

movement of the CO2 plume or pressure front. EPA believes that the phased corrective action 

approach is appropriate for GS projects, and retained it at §146.84(b)(2)(iv) in the final GS 

regulation. 

Letter ID: 0190 Comment ID: 24336 Letter Lines: 958 to 1001 

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

Comment: 3. AOR Reevaluation 

The proposed rule requires periodic reevaluation of the AOR determination on a 

frequency of at least once every ten years. We recommend an alternative 

approach. 

Reevaluation of the AOR is a significant exercise that ought to be triggered 

only when information suggests that there is actually a need for reevaluation. 

At the same time, it is important to recognize that injection well operations 

provide an ongoing stream of information - injection pressure information in 

particular - that might suggest the need for reevaluation of the AOR. 

Consequently, it does not make sense to require reevaluation of the AOR on any 

fixed schedule; instead, it makes sense to consider the need to reevaluate the 

AOR on a regular basis, and to reevaluate the AOR if - but only if - there is 

evidence of a need to do so (i.e., if information becomes available that is 

materially inconsistent with assumptions underlying an existing AOR 

determination). 

The proposed rule would already require a semi-annual report of injection 

operations. 73 Fed. Reg. at 43540. We recommend that these periodic reports be 

annual, consistent with Class II requirements, and that these reports include an 

32
assessment of the need for reevaluation of the AOR. Specifically, we support the 

Ground Water Protection Council’s CO2 Committee recommendation 7.6 that 

operators: 

Report annually, or at a frequency acceptable to the Director, the 

characteristics and cumulative volumes (annual and total) of injected 

fluids, injection pressures, injection rates, annular pressures for each 

injection well, the results of any mechanical integrity tests conducted 

during this time period, available site integrity monitoring results, 

the extent of the injected CO2 and the pressure front based on current 

data. 

Update site operations as appropriate and site modeling results 

annually, or at a frequency acceptable to the Director, to reflect 

current data. Compare the updated results to the previous results. 

Identify and explain to the Director any discrepancies between the 

updated results and the previous results. 

This approach will provide a reasonably frequent consideration of the need for 

reevaluation of the AOR, ensuring that the AOR is reevaluated promptly when 

necessary but that there is no need to reevaluate the AOR when monitoring 

results remain consistent with modeling results such that a requirement to 

reevaluate the AOR would be unnecessary. 

Individual Response: EPA agrees that site-specific factors, including monitoring and operating 

data, should be considered in the reevaluation schedule, and notes that the AoR and corrective 

action plan must specify the site-specific monitoring and operational conditions that warrant 

reevaluation, as specified in §146.84(b)(2)(ii). In addition, the Director has discretion to require 

more frequent AoR reevaluation if he or she has reason to believe, based on site-specific 

information, that a five-year reevaluation schedule is not sufficiently protective of USDWs. 

However, EPA believes that setting a minimum reevaluation frequency is appropriate. In the 

final rule, the Agency changed the minimum frequency for the AoR reevaluation at §146.84(e) 

from ten years to at least every five years in the final GS rule. EPA believes that this revised 

frequency addresses commenters' concerns 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. In addition, the Director has discretion to require more 

frequent AoR reevaluation if he or she has reason to believe, based on site-specific information, 

that a five-year reevaluation schedule is not sufficiently protective of USDWs. 

Letter ID: 0190 Comment ID: 24337 Letter Lines: 1003 to 1039 

Comment Code: 3820 2.3.1 Well construction procedures 

Comment: C. Injection Well Construction Requirements 

1. Well Design 

33
Many years of experience with the Class II UIC program - including 35 years of 

CO2 injection in the EOR context - have demonstrated that the construction 

requirements for Class II injection wells are sufficient to ensure that injected 

fluids cannot escape from the intended injection zone via the injection well 

borehole. The proposed rule would nevertheless impose substantially more costly 

well construction requirements resembling those for Class I hazardous waste 

injection wells. The Proposed Rule specifically cites the buoyancy of CO2 as the 

justification for these requirements. See 73 Fed. Reg. at 43509. 

The buoyancy of CO2 in no way justifies the additional construction requirements 

proposed. The reason for this is straight-forward: by far the greatest driving 

force for fluid migration along an injection well borehole is the pressure 

build-up (or "cone of influence") caused by fluid injection during the operation 

of the injection well. The magnitude of this pressure influence is at its 

maximum at the point of injection, and - within the injection interval - it 

generally falls off logarithmically with lateral distance from the injection 

well borehole. At some distance from the injection well, the pressure influence 

of the injection activity can be expected to decline to the point where densitydriven flow (i.e., buoyancy) could become significant (at least in relative 

terms) as a driver for vertical fluid migration. At the injection well, however, 

the induced pressure gradient caused by the injection activity would so dwarf 

the impact of buoyancy as to render the latter insignificant. Accordingly, it 

would be unreasonable to suggest that buoyancy justifies significantly more 

demanding injection well construction requirements than have already proven to 

be sufficient in the case of Class II CO2 injection wells. 

Our specific recommendations with respect to well construction are as follows. 

EPA should rely primarily on the basic performance standards for well 

construction stated in proposed 40 C.F.R. 146.86(a) rather than on less flexible 

well design specifications. This approach has proved effective in the context of 

the Class II program, and leaves permit-writers free to tailor well construction 

requirements to the particular circumstances involved. 

Individual Response: EPA disagrees that buoyancy is not a consideration that needs to be 

addressed in the GS regulations. Field and laboratory studies that evaluated two deep wells 

exposed to CO2 for nearly three decades have provided evidence of upward vertical flow of 

CO2. In Carey et al (2007), a sample of well cement collected from a section of well in the 

confining zone at SACROC showed evidence of cement alteration (carbonation) due to exposure 

from CO2. (The study was not able to determine whether the alteration was due to exposure to 

CO2 in the presence of water, dry CO2, or to a CO2-brine mixture.) In Crow et al (2009), a 

similar study was conducted on a CO2 production well that was drilled into and completed in a 

natural CO2 producing formation. This study concluded that CO2 had caused alteration 

(carbonation) of the well cement and acidification of fluids adjacent to the caprock. The study 

could not determine if the alteration was due to exposure from CO2 diffusion up into the 

34
overlying caprock or by upward CO2 migration through wellbore system defects (perhaps 

cement-caprock and/or cement-formation interfaces). In both studies, the CO2 apparently moved 

from the underlying reservoir into the well bore section located within the overlying caprock. 

These observations, especially in conjunction with the larger CO2 volumes and higher reservoir 

pressures anticipated with GS, justify the well construction requirements in the final GS rule in 

order to prevent deterioration of the materials between the well casing and the well bore that can 

result in unacceptable fluid movement. 

EPA adds that buoyancy of CO2 is one of several considerations for large scale GS that warrant 

the tailored construction requirements at §146.86. For example, seismic surveys at Sleipner 

showed that CO2 had migrated to the top of the 200 to 300 meter thick formation as early as 

three years after injection began. The overall behavior of CO2 at Sleipner is for it to migrate to 

the top of the formation and spread laterally from there (Chadwick et al 2006). Additionally, 

CO2 has the potential to be corrosive (in the presence of water or aqueous formation fluids 

during CO2 injection), and the volume of CO2 anticipated to be injected in Class VI wells is 

significantly greater than for Class II ER/ CO2 injection wells. 

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. 

Letter ID: 0190 Comment ID: 24338 Letter Lines: 1041 to 1048 

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment) 

Comment: EPA should delete the proposed design requirement for a surface casing cemented 

from the base of USDWs to the surface. While this is a commonly-imposed 

requirement and is generally appropriate, there are some conditions (e.g., when 

the base of the lowermost USDW is particularly deep) where such a requirement 

would be unduly burdensome and inappropriate. Accordingly, the need for surface 

casing to extend all the way through the base of the lowermost USDW should be 

left to the discretion of the permit writer rather than being predetermined in 

the text of the rule. 

Individual Response: EPA disagrees that the requirement should be deleted and believes that 

the regulations allow appropriate flexibility regarding the surface casing. The GS final 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 single or multiple strings of casing and cement. It 

does not, however, specify how cementing would be accomplished, and gives flexibility to the 

owner or operator to propose alternate methods to provide a sufficient amount of cement to meet 

the standard that USDWs are protected. EPA notes that there are many potential ways to meet 

the requirement, such as the use of staged cementing. EPA is developing guidance on the 

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

35
http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

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: 0190 Comment ID: 24340 Letter Lines: 1050 to 1058 

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

Comment: EPA should delete the proposed design requirement for the long-string casing to 

be cemented to the surface. Such a requirement - while arguably appropriate in 

the case of hazardous waste injection wells - can significantly complicate well 

construction, testing and repair, and is too costly to justify in the case of 

CO2 injection. Cement must of course be sufficient to prevent endangerment of 

USDWs, but the specific measures necessary to achieve this performance standard 

are dependent on site-specific conditions and are most appropriately determined 

in the permitting process rather than being predetermined in the text of the 

rule. 

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

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

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

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

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

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

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

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

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

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

Letter ID: 0190 Comment ID: 24341 Letter Lines: 1060 to 1068 

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment) 

Comment: EPA should retain the requirement for injection through a tubing and packer to 

facilitate continuous monitoring of a pressurized annulus. Wells designed with 

tubing and packer effectively provide two barriers, both of which must be 

breached before injectate could leave the borehole. At the same time, this 

design permits a proven method of monitoring that would permit detection of a 

breach in either barrier so that repairs can be made before both barriers fail. 

36
And a requirement to maintain positive pressure on the annulus, rather than 

always maintaining the annulus pressure in excess of the injected fluid pressure 

in the injection tubing will be sufficient as CO2 is not hazardous waste. 

Individual Response: EPA agrees that the use of tubing and packer in accordance with 

§146.86(c) will offer the best multiple-barrier protection of USDWs from endangerment. This 

requirement is retained in the final GS rule. See the discussion of Class VI well construction 

requirements in the preamble to the final GS rule for additional information. Additionally, EPA 

is developing guidance on the construction of Class VI wells. This guidance will be available on 

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

Letter ID: 0190 Comment ID: 24342 Letter Lines: 1070 to 1111 

Comment Code: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking 

comment) 

Comment: 2. Materials of Construction 

Besides specifying additional construction requirements, the proposed rule would 

require the use of degradation-resistant construction materials such as acidresistant cement and a corrosion-resistant casing. 73 Fed. Reg. at 43510. These 

requirements are based on the premise that CO2 is corrosive and that experience 

with CO2 injection in the EOR context suggests that corrosion is a significant 

issue. 73 Fed. Reg. at 43509-10. 

In fact, CO2 is not corrosive. What is corrosive is carbonic acid formed through 

the interaction of CO2 and water. This distinction is critical from a practical 

standpoint, because injected CO2 streams would at least generally be "dry" 

(i.e., dehydrated) and therefore non-corrosive. Once injected, the "dry" CO2 

would come into contact with naturally-occurring water in the subsurface, 

creating carbonic acid. However, an injection well would inject CO2 far more 

rapidly than the CO2 could mix with water, creating a CO2 plume that would 

immediately displace water away from the point of injection. While some residual 

water saturation would remain, the potential for carbonic acid formation in the 

immediate vicinity of the injection well would be limited. In this situation - 

which can be expected to be typical in the carbon sequestration context - there 

is no basis to suggest that injected CO2 is corrosive or that injection wells 

must be designed and constructed to resist a severely corrosive environment. 

Class II experience with CO2 injection supports this conclusion. Corrosion is 

sometimes an issue for injection wells used to produce "wet" streams containing 

oil, brine, and CO2 fractions brought up in the course of EOR/EGR operations. 

However - and this is the relevant point in the GS context - "dry" CO2 injection 

systems have operated for many years without the need for corrosion-resistant 

construction or the occurrence of corrosion-related problems. 

37
Well construction requirements under the UIC program generally require that 

operational conditions and the nature of formation fluids and proposed injectate 

be considered in well construction, and these general requirements have served 

well. Thus, while there may be some Class VI CO2 injection scenarios in which 

corrosion-resistant materials may be required, there is no technical basis for 

any general presumption that they are necessary or should be required. 

It should also be noted that the choice of casing and cement materials should be 

based on planned operating life of the injection well, not the ultimate duration 

of the GS program. The potential for longer term exposure of well components 

after injection has ceased will depend upon - and can be mitigated by - measures 

implemented at closure, such as plugging. 

Individual Response: EPA clarifies that it is when CO2 is in the presence of water or formation 

fluids that it can be corrosive to well materials. Reference to corrosiveness of the CO2 stream in 

§146.86 is intended to mean CO2 in the presence of water or formation fluids. EPA also notes 

that while a "dry out zone" (i.e., an area that is free of liquids) might form during injection (e.g., 

Birkholzer et al, 2008), no modeling study or other information is available about the postinjection period. At some point in the post-injection period, the near-wellbore environment may 

again become hydrated increasing the risk of cement corrosion. Several studies including field, 

laboratory, and modeling studies have found that pH drops in the formation fluid, indicating at 

least partial mixing of the carbon dioxide and formation water (Kaszuba et al, 2005; Kharaka et 

al, 2006; Birkholzer et al, 2008). The risk of creating acidic fluids that could come in contact 

with well materials and cements is addressed by the construction requirements in §146.86 to 

ensure protection of USDWs from endangerment. 

EPA disagrees that the casing, cement or other materials should only be designed for the period 

of the injection process, rather than the life of the sequestration project. GS projects are 

anticipated to have long life spans in comparison to other types of deep injection wells. Not only 

must Class VI wells be able to function safely and properly over the lifespan of the GS project, 

but they must be constructed such that USDWs remain protected after well plugging. The 

requirements at §146.86 will ensure that the well can maintain integrity throughout the proposed 

life span of the project, including after the injection well is plugged and through the postinjection site care period and beyond. While the risk profile of a GS site will decrease following 

cessation of injection, EPA believes that Class VI wells must be designed to protect USDWs 

from endangerment for the life of the project. Furthermore, rigorous casing and cementing help 

ensure that the Class VI well will not serve as a conduit for movement of fluids associated with 

future injection operations. 

Letter ID: 0190 Comment ID: 24343 Letter Lines: 1113 to 1135 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: D. Logging, Sampling and Testing Prior to Injection Well Operation 

While we have other specific concerns that are addressed in our detailed 

38
comments, our principal concern is that the logging, sampling and testing 

requirements of the proposed rule are overly rigid and prescriptive. In 

particular, the proposed rule appears to proceed from the premise that all of 

the information that could usefully be obtained from the logging, sampling and 

testing of a borehole should be obtained from the logging and testing of every 

borehole. Such an approach would be wasteful and unnecessarily burdensome. 

Our concerns are particularly acute with respect to the formation sampling and 

testing requirements specified in proposed section 40 C.F.R. 146.87(b) and (d). 

While there are likely to be cases in which very little site-specific 

information is available prior to drilling, there will be other cases in which 

vast amounts of information are or will be available and the incremental value 

of another exhaustive set of logs, samples and tests would be minimal. For 

example, extensive logging, sampling and testing clearly should not be necessary 

where there are multiple other injection wells or stratigraphic test wells that 

have been (or are being) used to gather the same kind of information for the 

same geologic formations and the same area. Accordingly, it is important to 

ensure that logging and testing requirements be tailored to the circumstances 

involved so that that costly and duplicative logging, sampling and testing 

requirements can be avoided. 

Individual Response: EPA believes that the logging and testing requirements in the GS rule are 

appropriate and necessary. The requirements at §146.87 stem from existing knowledge and 

practices in place for other injection well classes and within the oil and gas industry, and are 

tailored to the special characteristics of CO2 injection for GS. 

EPA is developing guidance on monitoring and testing that will describe recommended tests and 

procedures to assist owners/operators and Directors in evaluating the requirements for preoperational logging and testing under §146.87. This guidance will be available on EPA’s website 

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

EPA clarifies that §146.87(b) provides some flexibility. EPA notes that §146.87(b) allows 

information on cores from nearby wells to be submitted if the owner or operator can demonstrate 

that core retrieval is not possible and that cores from nearby wells are representative of 

conditions at the Class VI well. EPA clarifies that, at a minimum, reports on cores of injection 

zones and confining zones, and samples of formation fluids must be submitted. Section 

146.87(b) gives the Director authority to require the owner or operator to core other formations 

in the borehole if necessary to provide sufficient geologic information to verify that the site is 

suitable for GS. 

Letter ID: 0190 Comment ID: 24344 Letter Lines: 1137 to 1142 

Comment Code: 4110 2.4.1.1 Injection pressure limitations 

Comment: E. Injection Well Operating Requirements 

39
1. Injection Pressure Limitations 

We support the discussion and recommendation on injection pressure limitations 

presented in the Joint Letter resulting from the multi-stakeholder discussion. 

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

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

EPA emphasizes that injection pressure limits are important to protect against fracturing of the 

confining zone, and that the requirement at §146.88(a) that the pressure in the injection zone not 

exceed 90 percent of the fracture pressure provides a margin of safety in the well operation and 

protects USDWs from endangerment. If the Director determines, based on a review of the 

information collected as part of site characterization, that a lower injection pressure limitation is 

appropriate, the Director has the authority to set a lower limit in the operating permit than the 

limit established in the rule. 

Letter ID: 0190 Comment ID: 24345 Letter Lines: 1144 to 1171 

Comment Code: 4100 2.4.1 Injection parameters 

Comment: 2. Pressurized Annulus 

The proposed rule would require a pressurized annulus with an annulus pressure 

exceeding the pressure in the injection tube. While we support the proposed 

requirement for a pressurized annulus, we oppose the requirement that annulus 

pressure exceed injection tube pressure. 

The concept that annulus pressure should exceed injection tube pressure was 

introduced in the context of hazardous waste injection, where it reflected an 

extreme sensitivity to even the most remote possibility of a release of 

hazardous waste (the requirement was designed to ensure that injection tube 

leaks would cause annulus fluid to leak into the injection tube rather than 

allowing injectate to enter the annulus). The same extreme level of sensitivity 

obviously isn't warranted in the context of CO2 injection; as a result, the 

additional operating and maintenance costs typically needed to maintain an overpressurized annulus would not be justified. 

A pressurized annulus would permit detection of casing leaks whether or not 

annulus pressure exceeds injection pressure. Similarly, any significant pressure 

differential between in annulus and injection pressure would permit prompt 

detection of a tubing leak whether or not annulus pressure exceeds injection 

pressure. Accordingly, a requirement for a pressurized annulus is sufficient to 

protect USDWs without any requirement that annulus pressure exceed injection 

pressure. Indeed, a requirement that annulus pressure exceed injection pressure 

could - depending on the site conditions involved - do more to limit than 

enhance the sensitivity of leak detection. Consequently, the determination of 

annulus pressure should be left to the permitting process, without any 

40
presumption in favor of an over-pressurized annulus. 

Individual Response: EPA believes that maintaining an annulus pressure that is higher than the 

injection pressure, as required at §146.88(c), would ensure that if there are leaks in the tubing, 

the annulus fluid would move into the tubing, rather than the injectate moving out of the tubing 

and potentially along the length of the well. EPA adds that many characteristics of the annulus 

fluid and the injectate, including density as the commenter suggests, must be considered in 

maintaining annulus pressure and that fluid density should be considered when establishing an 

annulus pressure value at the surface. EPA also believes this requirement is appropriate for Class 

VI wells given the potential high volumes and supercritical nature of the CO2 injectate, potential 

geomechanical stresses in the wellbore, and the potential for movement of the CO2 in the event 

of a mechanical integrity loss. 

Letter ID: 0190 Comment ID: 24346 Letter Lines: 1173 to 1184 

Comment Code: 4520 2.5.1 Continuous internal mechanical integrity monitoring (seeking 

comment) 

Comment: 3. Continuous Monitoring 

As already indicated, we support continuous annulus and injection pressure 

monitoring for leak detection purposes. Continuous monitoring of injection rate, 

volume, and injectate temperature is also appropriate, but the proposed 

requirement for continuous monitoring of annulus fluid volume is unnecessary and 

(depending on what is actually contemplated) impractical. There is ample UIC 

program experience demonstrating that continuous monitoring of annulus fluid 

volume is not required for any purpose. For leak detection, pressure monitoring 

- with periodic records of annulus fluid additions and withdrawals - has proved 

to be sufficient. 

Individual Response: EPA acknowledges the comment and agrees that continuous pressure 

monitoring to demonstrate internal mechanical integrity required under §146.89(b) is important 

given the potential corrosive impact of CO2 and impurities on well materials, the potential 

geomechanical impacts to well integrity due to CO2 phase changes, and the temperature and 

pressure effects associated with injecting supercritical CO2. The final GS rule retains this 

requirement. 

EPA acknowledges that recording annulus fluid volume may not always be appropriate. EPA 

believes that knowing annulus fluid volume as required at §146.88(e) is a necessary component 

of monitoring well mechanical integrity, but believes that knowing the annulus fluid volume 

added is sufficient to meet the intent of the requirement. The final GS rule requires that owners 

or operators use continuous recording devices to monitor injection pressure, rate, and volume; as 

well as the pressure on the annulus between the tubing and the long string casing. It also 

modifies the requirement in the proposed rule to continuously monitor annulus fluid volume; it 

now requires recording of annulus fluid volume added. See §§146.88(e); 146.89(b); and 146.90 

41
(b). 

Letter ID: 0190 Comment ID: 24347 Letter Lines: 1185 to 1200 

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment) 

Comment: 4. Down-Hole Shut-Off Valves 

EPA proposes to require automatic shut-off valves down hole as well as at the 

surface. Such a requirement is unnecessary and would be costly and completely 

unprecedented in the UIC program. In fact, the "down-hole" valves EPA is 

referring to are designed for off-shore use, and are intended to provide a shut 

off point below the sea bed in the event of a casing breach between the sea bed 

and the surface. Such valves are not appropriate for use deep under ground, and 

their use as proposed would increase well construction and operation costs and 

significantly complicate well testing and workovers. 

In any event, there is simply no justification to require the use of down-hole 

shut-off valves in the CO2 injection context. Class I hazardous waste injection 

wells are not required to have down-hole automatic shut-off valves, and there is 

no basis at all to suggest that CO2 injection entails higher risks warranting 

such costly and problematic measures. 

Individual Response: After evaluating the risks and benefits of down-hole shut-off systems and 

considering additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from 

endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or operators of 

onshore Class VI wells install automatic surface shut-off devices. The rule affords Director's 

discretion to mandate automatic down-hole shut-off devices in onshore situations that may 

warrant their use. The Agency agrees that offshore Class VI wells present unique construction 

and operational conditions, including isolation from shorelines and the need to construct wells 

through the water column and the subsurface, which may delay response time in the event of 

well difficulties. The rule requires, at §146.88(e)(3), that owners or operators of offshore wells 

within State territorial waters install automatic down-hole shut-off systems. 

Letter ID: 0190 Comment ID: 24348 Letter Lines: 1202 to 1221 

Comment Code: 4250 2.4.3 Corrosion monitoring and control 

Comment: 5. Corrosion Monitoring 

As already discussed, CO2 is not corrosive in the absence of water and there is 

no basis to assume that GS wells will typically be used to inject corrosive 

fluids or will always be in contact with corrosive conditions in the injection 

42
zone. A general requirement for corrosion monitoring is therefore unnecessary 

and inappropriate. 

Even if there were some basis for corrosion concerns, a requirement for 

corrosion monitoring would be excessive, because the proposed rule already 

includes other provisions sufficient to address the risks corrosion would 

present. In particular, the proposed rule would require that injection wells be 

designed and constructed for their intended service. This requirement would 

address the potential for corrosion even if (as we recommend) the burdensome and 

unnecessary provisions expressly requiring use of corrosion-resistant materials 

is excised. In addition, the requirements for a tubing and packer design would 

protect against corrosion leaks, both by providing secondary containment of the 

injectate and by permitting continuous annulus pressure monitoring (also 

required) to ensure that corrosion leaks could be detected and repaired before 

both layers of containment would be breached. 

Individual Response: EPA disagrees with commenter's assertions that corrosion monitoring is 

unnecessary or excessive. CO2 in the presence of water (including water with NOx, SOx, and 

H2S impurities) can be corrosive to well materials and cements. Thus, although a CO2 stream 

may be dry, the potential for corrosion of well materials down-hole, where the injectate can 

potentially mix with water in the target formation, must be considered. While the construction 

requirements at §146.86 were designed to protect against corrosion, EPA believes that multiple 

barriers against corrosion-related failures, including construction and monitoring requirements, 

are necessary in order to protect USDWs from endangerment. 

Several laboratory studies and a limited number of field studies have investigated and 

characterized the effects of carbonic acid on well materials. Laboratory studies (e.g., Kutchko et 

al., 2007; Kutchko et al., 2008; Akervoll, 2005) consistently identify alterations (typically 

carbonation) of cement as the result of interactions between cement and CO2-saturated brine. 

Currently, there are only a few analyses of cement from wells that have been in prolonged 

contact with CO2 in actual field (down-hole) conditions. Evaluation of cement from a well at the 

Scurry Area Canyon Reef Operators Committee (SACROC) site showed alteration, but did not 

show degradation that compromised the structural integrity of the cement (Carey et al., 2007). In 

another study, cement samples were collected and analyzed from a CO2 production well in a 

natural CO2 reservoir in Colorado exposed to a CO2-water down-hole environment for 30 years 

(Crow et al., 2008). The study found evidence of reaction between the CO2-rich water and the 

cement. 

Oil industry research also addresses the effects of corrosion of steel tubing and pipes. Lopez et 

al. (2003) noted that 60 percent of oilfield failures are related to the effects of carbonic acid from 

produced brines on carbon and low alloy steels. A report by CO2 Norway (2004) notes that in 

some CO2 ER floods in the Permian Basin of Texas, bare carbon steel tubing has been used 

successfully. 

Laboratory investigation of cement alteration/degradation is an ongoing research area. Few field43
based studies have been completed to date. Although the laboratory and field studies currently 

available suggest that corrosion problems may not be serious, there is not enough data to rule out 

potential corrosion problems of steel components of injection wells. Given the anticipated long 

lifespan of a Class VI well and the difficulties that would be associated with a corrosion-related 

well failure, EPA believes that corrosion monitoring in the down-hole environment is justified in 

order to protect USDWs from endangerment. 

Letter ID: 0190 Comment ID: 24349 Letter Lines: 1223 to 1236 

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

USDW 

Comment Code: 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth 

Comment: 6. Injection Depth 

As already discussed, we oppose restricting Class VI injection to either to any 

minimum injection depth or to injection zones below the lowermost USDW. As EPA 

recognizes, 73 Fed. Reg. at 43511-12, such restrictions are not necessary to 

protect USDWs and would serve only to preclude the use of what might otherwise 

be appropriate CO2 storage reservoirs. EPA should permit GS under any 

circumstances in which the Director can determine that USDWs will not be 

endangered. 

Recognizing that the USDW definition is so broad as to include formations that - 

because of their location, depth, or other factors - could not reasonably be 

expected to serve as sources of drinking water, we support the appropriate use 

of aquifer exemptions to facilitate GS. 

Individual Response: EPA agrees that it is not appropriate to set a minimum injection depth for 

GS projects. EPA 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 

44
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: 0190 Comment ID: 24350 Letter Lines: 1238 to 1260 

Comment Code: 4490 2.4.5 Use of tracers and potential impact on human health or ecosystems 

(seeking comment) 

Comment: 7. Tracers 

We strongly oppose any requirement for the use of tracers, including any such 

requirement that could be imposed at the discretion of the Director. 

There are at least two fundamental issues with respect to tracers. First, 

tracers are unlikely to enhance the protection of USDWs. This is true not just 

because the Class VI regulations are designed to minimize the likelihood of the 

kind of leakage tracers would ostensibly help detect, but because - even in the 

event of such a leak - tracers are not likely to be especially useful in leak 

detection (as discussed in the context of monitor wells, fluid monitoring in the 

deep subsurface provides only very localized information and is unlikely be very 

effective in leak detection whether or not tracers are used). Second, tracers 

are at least as likely to create "false positives" as to aid in the detection of 

actual down-hole leaks. The problem in this respect is simple: it is much easier 

for accidental leaks and releases to occur in the surface environment than in 

the deep subsurface. 

A final consideration is perhaps the most obvious: a requirement for tracers 

would be unique in the UIC program, and would unavoidably undermine public 

confidence in permitting determinations that - by definition - would be based on 

the premise that leaks from injection wells and properly permitted injection 

formations are extraordinarily unlikely to occur. 

Individual Response: EPA believes that, in some circumstances, tracers can be an important 

component of a multifaceted approach to monitoring GS projects. However, the Agency 

recognizes that tracers may not be appropriate in all GS projects. For this reason, EPA does not 

require the use of tracers at all GS sites; however, the Director has discretion to require their use 

if he/she determines that the use of tracers could improve monitoring of the site and enhance 

USDW protection from endangerment. 

EPA disagrees that using tracers, where appropriate, would overstate the danger of CO2 or GS. 

Rather, EPA believes that providing the public with important information about the project, 

including how tracers would be an integral part of the site monitoring plan, will be a key part of 

improving public acceptance of specific projects and GS technology in general. 

While the intent of the GS regulations is to prevent leaks of CO2 to USDWs, EPA clarifies that 

45
all of the protective components of the GS regulation, including a comprehensive monitoring 

program per §146.90 (which includes testing of the well, ground water quality monitoring, and 

tracking of the CO2 plume and pressure front) support a multi-barrier approach to protecting 

USDWs. Additionally, some studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; 

McCallum et al., 2005) found that tracers can provide useful CO2 monitoring information at 

injection wells both at depth and at near-surface locations. At Frio, tracers enabled quantification 

of CO2 plume behavior and provided a technique for model validity testing (McCallum et al., 

2005). EPA will continue to track research related to tracer use. The Agency plans to, every six 

years, 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: 0190 Comment ID: 24351 Letter Lines: 1262 to 1283 

Comment Code: 4500 2.5 Proposed Mechanical Integrity Testing (MIT) Requirements (40 CFR 

146.89) 

Comment: F. Mechanical Integrity Testing (MIT) Requirements 

The proposed rule suggests that "MIT requirements for GS wells should be 

tailored to address the unique properties of CO2, specifically its buoyancy and 

potential corrosivity." 73 Fed. Reg. at 43513. As previously discussed, however, 

the buoyancy of CO2 is a relatively trivial factor in relation to the cone of 

influence created by injection pressure during injection, a factor that makes 

buoyancy virtually irrelevant as a driving force for upward migration through 

the injection well borehole during the operational life of a GS well. 

Accordingly, there is no basis to suggest that the buoyancy of CO2 is a 

significant factor to consider in establishing mechanical integrity testing 

requirements for GS wells. Similarly - as also previously discussed - CO2 is not 

corrosive and cannot be expected to cause substantial corrosion problems for the 

injection well (including down-hole cement) unless the CO2 stream itself 

contains water. Consequently, concerns related to corrosion do not justify 

particularly stringent MIT requirements for GS wells. 

Experience with CO2 in the EOR context fully supports these conclusions. In 

fact, the Class II MIT requirements have been sufficient for CO2 injection in 

the EOR/EGR context, and there is no reason why they should not be sufficient in 

the GS context as well. Accordingly, the proposed MIT requirements for Class VI 

wells are more stringent and prescriptive than necessary. 

Individual Response: EPA disagrees with this comment. EPA has identified buoyancy as one of 

the unique characteristics of CO2 that warrants special consideration. The Agency believes that 

buoyancy of the injected CO2 coupled with other characteristics of GS operations, including the 

large injection volumes and timeframes of storage, present operating circumstances at Class VI 

wells that are different from other classes of wells and associated injectates regulated by the UIC 

Program. 

46
Supercritical CO2 has a lower density than the native formation fluids in the target injection 

formations typically anticipated for GS. Once injected, the more buoyant CO2 will have a 

tendency to migrate upwards. This expected movement is similar to the situation found in some 

Class I wells (see Revision to the Federal UIC Requirements for Class I--Municipal Wells in 

Florida; 65 FR 42234, July 7, 2000). Well monitoring in Florida identified upward fluid 

movement from some Class I municipal wells attributed to the lower density of the injection 

fluid (in this case due to lower TDS) compared to the native formation fluids. The injection 

fluids rose to the top of the injection zone preferentially through fractures. Such migration could 

occur through conduits in the injection wellbore as well as in the target formations. In the case of 

GS, any cracks or fractures in the cement casing for a GS injection well would also serve as 

conduits for upward migration of more buoyant fluids. External MITs, which test for movement 

along the borehole, are therefore appropriate requirements for GS wells. 

EPA disagrees that the MIT requirements for Class VI wells are excessive. MITs are a longstanding and proven method of providing early warning of potential problems in the injection 

well system before they lead to leakage and/or endangerment of USDWs. 

EPA also disagrees that corrosivity is not a concern. While some studies of cement performance 

have shown encouraging results, other information gathered through research and field data 

provided in the rulemaking docket, show evidence of chemical alteration and suggest a potential 

for degradation to occur and potentially endanger USDWs. Although laboratory and field studies 

suggest that corrosion problems may not be severe, such problems cannot be conclusively ruled 

out. Laboratory exploration of cement alteration and degradation is an ongoing research area, 

and field-based studies are very few. There also does not appear to be a clear consensus on the 

corrosion risks for the steel components of injection wells. Given the anticipated long lifespan of 

Class VI wells and the difficulties that would be associated with a corrosion-related well failure, 

EPA believes that the MIT requirements at §146.89 are justified. 

A comprehensive review of MIT results found that Class I wells injecting corrosive fluids fail 

MITs at rates two to three times higher than those that inject non-corrosive fluids (USEPA, 

1999). Given the potential for CO2 to be corrosive (when in the presence of water), there is a 

potential risk factor for MIT failure and the tailored MIT requirements are appropriate. 

EPA agrees that Class II well operators have decades of experience injecting CO2. However, 

EPA believes that significant operational differences exist between Class II and Class VI wells. 

For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly 

greater than for Class II wells. Also, reservoir pressure conditions will be different with ER 

production (extraction) serving to reduce reservoir pressure for Class II operations while Class 

VI injection operations will have no comparable de-pressuring activities. For these reasons, EPA 

believes that injection of CO2 for GS warrants more frequent MITs to provide sufficient early 

warning of the potential for MI failures due to the corrosivity of the CO2 or reservoir pressure 

conditions associated with CO2 GS. 

47
Letter ID: 0190 Comment ID: 24352 Letter Lines: 1285 to 1287 

Comment Code: 4520 2.5.1 Continuous internal mechanical integrity monitoring (seeking 

comment) 

Comment: As already indicated, we support the requirement for continuous injection and 

annulus pressure monitoring as a means to ensure "internal" mechanical 

integrity. With regard to "external" mechanical integrity, we believe that the 

Individual Response: EPA agrees with the commenter regarding the importance of 

demonstrating internal mechanical integrity (MI), required under §146.89(b). EPA believes that 

continuous pressure monitoring of GS wells, instead of periodic testing (which is required for 

most other types of deep injection wells), is appropriate because the potentially corrosive nature 

of CO2 injectate streams in the presence of water enables the immediate identification of 

corrosion-related internal mechanical integrity problems that could lead to significant well 

problems and failure. The final GS rule retains this requirement. 

Letter ID: 0190 Comment ID: 24353 Letter Lines: 1287 to 1291 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: integrity. With regard to "external" mechanical integrity, we believe that the 

test methods employed and the frequency of testing should be within the 

discretion of the permit writer, subject only to a requirement that external 

mechanical integrity be demonstrated through approved MIT techniques at least 

once every five years. 

Individual Response: EPA believes that the MITs described in the rule at §146.89 are effective 

methods and have been used successfully by injection well operators for decades and provide an 

important early warning of potential problems in the injection well system. 

EPA clarifies that the regulations provide the Director discretion to require additional methods 

or, with the Administrator's approval, to approve the use of alternative MIT methods based on 

specific information about the site or the well. See §146.89(e). 

The final GS regulation retains the requirement that owners or operators of Class VI wells 

demonstrate injection well external mechanical integrity at least once annually at §146.89(c). 

EPA believes that the annual mechanical integrity testing is appropriate for Class VI wells and 

believes this is justifiable for the protection of USDWs from endangerment given the unique 

nature of CO2 GS relative to other injection operations, including the potential corrosive impact 

of CO2 in the presence of water and impurities on well materials, the potential geomechanical 

impacts to well integrity due to CO2 phase changes, the temperature and pressure effects 

associated with injecting supercritical CO2, and the buoyant nature of the injected CO2. Because 

of the unknown long-term effects of CO2 GS, EPA chose a more conservative initial approach in 

the early stages of deployment for GS. 

48
In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found 

that Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those 

that inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., 

in the presence of water or aqueous formation fluids), there is a potential risk factor for MIT 

failure and, for this reason, EPA believes that the tailored MIT requirements in the final GS rule 

are appropriate. 

EPA adds that it is using an adaptive approach to regulating GS. The Agency plans to collect and 

review data every six years on GS projects, including MIT data, 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: 0190 Comment ID: 24354 Letter Lines: 1293 to 1308 

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment) 

Comment: G. Testing and Monitoring Requirements 

The preamble to the proposed rule indicates that "EPA considers CO2 plume and 

associated pressure front monitoring to be necessary for verification of model 

predictions." 73 Fed. Reg. at 43514. This proposal unnecessarily undermines 

confidence in the modeling demonstrations that can and should be relied upon to 

support determinations that injected CO2 will not endanger USDWs. Modeling 

provides a conservative assessment of the potential for movement of injected 

fluids in the subsurface, not a precise "prediction" of actual fate and 

transport that can or should be "verified" on the basis of elaborate, costly, 

and uncertain efforts to observe the actual movement of fluids in the 

subsurface. As experience with hazardous waste injection shows, injection well 

operational data and the results of pressure fall-off tests provide ample data 

to validate the results of modeling. The additional monitoring requirements 

proposed in the GS context go beyond what is required for Class I hazardous 

waste injection wells; these requirements are excessive and unnecessary. 

Individual Response: EPA agrees that good site selection and modeling are crucial elements of 

a successful GS project, but disagrees that this is an effective substitute for rigorous site 

monitoring, including pressure monitoring. 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 also 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. 

49
EPA disagrees that plume and pressure front monitoring are not justified for Class VI wells. The 

Agency recognizes that while there are similarities between injection of wastes for disposal 

(Class I) and GS (Class VI), there are significant differences as well. Important unique 

considerations for GS include the buoyancy of CO2, its corrosivity when in contact with water, 

its low viscosity (i.e., high mobility), and the very large injection volumes that are anticipated. 

There is also a degree of uncertainty regarding the behavior of large volumes of CO2 in the 

subsurface after injection. Given these characteristics of anticipated GS projects, EPA believes 

that plume and pressure front monitoring at §146.90(g) are justified to provide early warning of 

any unforeseen fluid movement that might endanger USDWs. 

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. 

§146.90(g)(2) requires owners or operators to track the position of the CO2 plume using indirect 

methods (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO2 

detection tools), unless the Director determines based on site-specific geology that such methods 

are not appropriate. For example, geophysical methods are difficult to execute in areas that are 

structurally and topographically complex or where lithologies have limited contrast in density, 

porosity, permeability, and other physical properties. EPA clarifies that this determination will 

be made by the Director based on the site-specific geologic information submitted by the owner 

or operator with their permit application. 

EPA disagrees that pressure fall-off tests are an appropriate substitute for monitoring pressure 

changes in the injection zone. Pressure fall-off tests provide information only in the vicinity of 

the injection well(s) and measure pressure conditions within the injection zone only. Direct 

monitoring of pressure changes in the injection zone can provide advance warning of movement 

of CO2 or brine that might ultimately endanger a USDW. 

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

believes that 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). 

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. The guidance can be found on EPA’s website at 

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

Letter ID: 0190 Comment ID: 24355 Letter Lines: 1310 to 1318 

Comment Code: 4650 2.6.5 CO2 plume and pressure front tracking (seeking comment) 

Comment: 1. Monitoring CO2 Movement and Reservoir Pressure 

50
The preamble to the proposed rule specifically states that the "[m]onitoring of 

subsurface geochemistry and the position of the CO2 plume and pressure front are 

necessary to verify predictions of plume movement, provide inputs for modeling, 

identify needed corrective actions, and target geochemical and surface 

monitoring activities." 73 Fed. Reg. at 43514. Again, this is inconsistent with 

experience with Class I hazardous waste injection, where such monitoring has not 

been necessary and is not required. 

Individual Response: EPA disagrees that plume and pressure front monitoring are not justified 

for Class VI wells. The Agency recognizes that while there are similarities between injection of 

wastes for disposal (Class I) and GS (Class VI), there are significant differences as well. 

Important unique considerations for GS include the buoyancy of CO2, its corrosivity when in 

contact with water, its low viscosity (i.e., high mobility), and the very large injection volumes 

that are anticipated. There is also a degree of uncertainty regarding the behavior of large volumes 

of CO2 in the subsurface after injection. Given these characteristics of anticipated GS projects, 

EPA believes that plume and pressure front monitoring at §146.90(g) are justified to provide 

early warning of any unforeseen fluid movement that might endanger USDWs. 

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. 

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 also assure the public that 

GS projects are proceeding according to plan, provide sufficient information to the owner or 

operator and Director, or allow for appropriate actions to address any indication that USDWs 

may be endangered. 

Letter ID: 0190 Comment ID: 24356 Letter Lines: 1320 to 1344 

Comment Code: 4660 2.6.6 Geochemical monitoring 

Comment: a. Monitor Wells 

Monitor wells reaching the deep subsurface are problematic in a variety of 

respects. They are expensive to install, create potential pathways for vertical 

fluid migration, and - in the deep subsurface where natural fluid movement may 

be very slow or effectively non-existent - they have little potential to provide 

more than an isolated "point measurements." Monitor wells also have built-in 

51
confounding factors that include both the potential for well construction to 

impact fluid quality in the target sampling interval and the fact that sampling 

may itself cause fluid movement that might not otherwise occur. Because pressure 

fronts extend much further than injected fluid plume fronts during injection, 

pressure monitoring is more likely to be useful than fluid sampling, but costs 

would still be very high and the ability to detect relevant changes would still 

be difficult. For these reasons, EPA chose not to impose monitor well 

requirements on other classes of injection wells, though it did allow monitor 

wells to be used for Class I hazardous waste injection wells at the discretion 

of the Director to address particular circumstances at the site. See 52 Fed. 

Reg. 32446 at 32463-64 (August 27, 1987), 53 Fed. Reg. 28118 at 28141, 28144-45 

(July 26, 1988). Experience with hazardous waste injection does not commend the 

use of monitor wells even in that context, and there is no justification to 

impose a more stringent an approach for the injection of CO2. Accordingly, we 

recommend that the potential for gaining useful information from monitor wells 

be carefully considered in developing an appropriate monitoring plan and that 

such wells be used only as justified by specific circumstances. (See Attachment 

A, 146.90(a).) 

Individual Response: EPA believes that monitoring using wells in the injection zone, e.g., for 

pressure monitoring as required at §146.90(g)(1), can be safely performed if the wells are 

constructed to prevent flow between the injection zone and USDWs or other layers above the 

confining zone. Such construction technologies exist and have been used in the oil and gas 

industry for years. EPA believes that properly constructed monitoring wells will be a safe way to 

obtain the data that is essential to ensure that the injected CO2 remains confined in the injection 

zone and that pressure changes are not causing movement of formation or other fluids. To 

mitigate the risk of fluid movement, EPA requires owners and operators to submit a testing and 

monitoring plan that describes how the owner or operator plans to site and construct monitoring 

wells. EPA is developing guidance on well construction that will include recommendations for 

monitoring well construction. The guidance will be available on EPA’s website at 

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

While EPA chose not to impose similar monitoring requirements on other classes of injection 

wells (except for Class I hazardous waste injection wells), the Agency believes that a 

conservative, protective approach is appropriate, given the large volumes of CO2 being injected. 

EPA also acknowledges that complete coverage of the potential plume area or leakage in the 

subsurface is not possible through the use of monitoring wells. However, data from an 

appropriate number of monitoring wells sited based on site-specific information will provide 

direct information that is not otherwise obtainable and, along with other monitoring data, will 

support a broader understanding of fluid behavior at the site. 

EPA adds that the iterative process of monitoring, modeling, and AoR reevaluation is 

appropriate to verify that the CO2 plume and pressure front are moving through the subsurface 

as predicted, verify the accuracy of the delineation model (or identify needed changes), and 

refine testing and monitoring activities to ensure that USDWs are protected from endangerment 

52
and that there would be adequate warning of potential problems at the site before any 

endangerment could occur. 

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

believes that 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). 

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. 

Letter ID: 0190 Comment ID: 24357 Letter Lines: 1346 to 1352 

Comment Code: 4655 2.6.5.1 Plume tracking techniques/geophysical methods (seeking 

comment) 

Comment: b. Geophysical Methods for Plume Tracking 

As an alternative to monitor wells, the proposed rule suggests that it may be 

possible to use remote geophysical techniques for "plume tracking." 73 Fed. Reg. 

at 43515. Unfortunately, the technologies available would be very expensive to 

employ on the scale required. Seeking to achieve greater precision can lead to 

an expensive and unnecessary quest. 

Individual Response: 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 required unless the Director determines, based on site-specific geology, that such methods 

are not appropriate. 

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 also 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. 

53
EPA is affording Director's discretion regarding the use of geophysical techniques at some sites 

because the Agency recognizes that geophysical methods are not appropriate in all geologic 

settings. For example, geophysical methods are difficult to execute in areas that are structurally 

and topographically complex or where lithologies have limited contrast in density, porosity, 

permeability, and other physical properties. EPA clarifies that this determination must be made 

by the Director based on the site-specific geologic information submitted by the owner or 

operator with their permit application. 

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. 

Letter ID: 0190 Comment ID: 24358 Letter Lines: 1354 to 1368 

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

comment) 

Comment: 2. Surface Air and Soil Gas Monitoring 

The goal of any UIC program regulations for GS should be to ensure that injected 

CO2 streams remain confined in the subsurface and do not endanger underground 

sources of drinking water. We are recommending sufficient requirements to ensure 

that this goal is achieved. As EPA seems to recognize, surface air or soil gas 

monitoring would impose substantial costs and the results of such monitoring 

would be subject to a host of confounding factors. Worst of all, such monitoring 

would be aimed at leakage of CO2 all the way to the surface, which - in the case 

of any properly-permitted GS project - would by definition be an extraordinarily 

low probability scenario. Accordingly, such requirements should not be imposed, 

nor should regulators have discretion to impose them. If there is any serious 

concern that injected CO2 might actually vent to the surface in a particular 

location, injection should not be permitted at that site in the first place. The 

regulations should not suggest otherwise. 

Individual Response: EPA acknowledges that air and soil gas monitoring are subject to sitespecific limitations 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. If surface 

monitoring were the only monitoring method employed to ensure USDW protection, direct 

correlation of CO2 at the surface with CO2 in the subsurface might be difficult; however, when 

combined with information gathered through other monitoring techniques required of GS well 

owners and operators (e.g., monitoring wells, geophysical techniques), air and soil gas 

monitoring may provide valuable data on the magnitude and location of a leak. 

54
The decision to use surface monitoring and the selection of monitoring methods will be sitespecific (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 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). 

Used in conjunction with deep subsurface monitoring, as required at §146.90, and as part of a 

multi-barrier approach to protecting USDWs from endangerment, surface air and soil gas 

monitoring will increase USDW protection, enable immediate notification of the UIC Director in 

the case of potential USDW endangerment, and facilitate remedial action. 

Letter ID: 0190 Comment ID: 24359 Letter Lines: 1370 to 1383 

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

CFR 146.85) 

Comment: H. Financial Assurance 

We support EPA’s flexible approach on financial assurance methods. It would be a 

mistake to impose any regulatory restrictions that would preclude the use of 

particular types of financial assurance or particular instruments, regardless of 

whether those are currently used for other classes of injection wells or in 

other EPA programs. Allowing for flexibility recognizes that operators are 

likely to use combinations of approaches and instruments to meet these 

requirements and that these combinations may change significantly over time as 

operators, program Directors and the financial markets gain more experience with 

geologic sequestration projects. EPA’s is wise to avoid any artificial 

constraints on the development of potentially acceptable means of achieving 

financial assurance. We recommend that this approach be retained in the final 

rule. 

Individual Response: EPA agrees that it is appropriate to allow a flexible approach for financial 

responsibility as long as USDWs are protected. 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)). 

Furthermore, EPA is developing guidance to help owners or operators, permitting authorities, 

and third parties choose and evaluate appropriate financial methods and states may set more 

55
specific financial responsibility requirements if they so choose. This guidance is available on 

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

Owners or operators may select different instruments for specific project activities. EPA also 

anticipates that the availability of third-party GS financial instruments will grow in response to 

demand for such instruments by GS well owners or operators. However, EPA will not allow for a 

separate financial responsibility demonstration for well plugging and PISC (e.g., a demonstration 

submitted prior to well plugging and the beginning of the post-injection site care period rather 

than the permit application). A demonstration of financial responsibility for all phases of the GS 

project will be required prior to issuance of a Class VI permit. See the final rule and preamble for 

further discussion of the EPA's final approach to financial responsibility. 

Given that the practice of GS is fairly new and EPA does not have enough information in 

supporting future prediction, 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. 

Letter ID: 0190 Comment ID: 24360 Letter Lines: 1416 to 1418 

Comment Code: 2020 1.5.1 Support Class VI designation 

Comment: Rule Provision: 144.1 

Proposed CCS Group Recommendations: Support revision to include a sixth class of 

Individual Response: EPA agrees that tailored requirements for Class VI wells are necessary to 

address the unique nature of injecting large volumes of CO2 and to ensure that USDWs are 

protected from endangerment. The GS rule contains tailored requirements for the permitting, 

geologic site characterization, AoR and corrective action, well construction, operation, 

mechanical integrity testing, monitoring, well plugging, post-injection site care, and site closure 

of GS wells that directly address issues unique to the nature of large-scale CO2 injection for GS. 

Letter ID: 0190 Comment ID: 24361 Letter Lines: 1421 to 1452 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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: Rule Provision: 144.6(b) 

Proposed CCS Group Recommendations: Add new paragraph (b)(4) 

(4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC 

SEQUESTRATION IS 

56
OCCURRING DURING OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL 

OR NATURAL GAS 

PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE THAN 

INSIGNIFICANT FUTURE 

PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION 

AND (II) 

OPERATING PRESSURES ARE NO HIGHER THAN REASONABLY NECESSARY TO 

PRODUCE SUCH 

VOLUMES OR RATES; 

Basis for CCS Group Comments: EPA’s Proposal would continue to regulate and 

permit injection of CO2 for EOR/EGR purposes as Class II injection "as long as 

any production is occurring." EPA has asked for comment on the merits of this 

approach "since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted." 73 Fed. Reg. at 43502. We recommend that the rules be 

clarified to provide more certainty about the applicability of Class II 

requirements where GS of CO2 occurs in connection with EOR/EGR activities. 

Specifically, the UIC rules should provide a "bright line" definition as to the 

applicable class of wells where CO2 injection for EOR/EGR production and for GS 

occur in tandem. 

The proposed language describing wells in classification (b)(4) establishes a 

"bright line" definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the 

current requirements of Class II. We have also agreed that the wells used for GS 

in oil and gas reservoirs that do not meet the criteria of (b)(4) should be 

subject to additional requirements. 

This is the same recommendation as presented by the multi-stakeholder group, in 

which the Carbon Sequestration Council participated. 

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

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

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

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

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

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

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

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

within their storage formations than Class II EOR projects. 

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 

57
projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. 

EPA is developing guidance on transitioning permits from Class II to Class VI. The guidance 

will assist Directors in determining whether an injection project should be transitioned from 

Class II, where the primary purpose is oil and gas production, to Class VI, where the primary 

purpose is long-term storage of large volumes of CO2. The guidance describes the recommended 

methods the Director may use to evaluate changes in risk to USDWs from projects, and how the 

Director may determine whether a project should be regulated within the Class II or Class VI 

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

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. For more information, please 

see the discussion on transition of Class II wells in the preamble to the final GS rule. 

Letter ID: 0190 Comment ID: 24362 Letter Lines: 1454 to 1495 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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: Rule Provision: 144.6(f) 

Proposed CCS Group Recommendations: (f) Class VI. used for geologic 

sequestration of carbon dioxide beneath the lowermost formation containing a 

USDW. Wells INJECTING A CARBON DIOXIDE STREAM FOR GEOLOGIC 

SEQUESTRATION 

EXCEPT THOSE WELLS DESCRIBED IN SUBSECTION (B)(4) OF THIS SECTION OR 

OTHERWISE 

EXCLUDED FROM THIS CLASS. 

Basis for CCS Group Comments: The changes to (b) and (f) are to recognize that 

EOR can have a storage component, which is consistent with EPA’s intent as 

expressed in the preamble. It is widely recognized that CO2 based EOR can 

provide a significant early opportunity for carbon storage. As EPA correctly 

recognizes, CO2 EOR operations can have a significant storage component through 

capillary trapping or other mechanisms. Operators experience supports this 

approach as they have seen that between 1/3 to 1/2 of the injected CO2 in EOR 

operations is trapped within the receiving formation during CO2 EOR operations. 

Following abandonment of EOR operations, assuming the CO2 not trapped in the 

receiving formation, has not been produced for use in another field, essentially 

all of the CO2 that has been injected can be permanently stored. 

We recommend that all GS into basalts, coal seams, and salt domes be conducted 

under Class V as experimental wells initially and then as commercial scale Class 

58
V wells/projects if the experimental projects demonstrate that these sites can 

be suitable for geological sequestration while preventing endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain enough 

experience to develop suitable permitting requirements for such wells and to 

tailor those requirements at both the pilot and commercial scales until the 

agencies are ready to adapt the Class VI regulations. 

There should not be a blanket prohibition concerning injection above USDW’s or 

at specific depths. This requirement is not necessary for the protection of 

USDWs and would remove a vast number of viable formations from consideration. It 

has been shown that it is possible to operate CO2 injection wells in an EOR 

context without endangering USDWs that are located below the injection zone. An 

excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Under the proposed rule, there are other measures that 

would provide real assurance of formation integrity and require operators to 

demonstrate that their project will not endanger USDWs, making the lowermost 

USDW restriction unnecessary. Instead, operators should be able to show adequate 

containment to prevent endangerment of USDWs both above and below the injection 

zone used for geologic sequestration. 

Individual Response: As described above regarding the suggested edit at 144.6(b), EPA did not 

make the suggested change. The Agency disagrees that wells injecting CO2 for the primary 

purpose of long-term storage should be regulated under Class II requirements. 

Regarding injection into basalts, coal seams, and salt domes, EPA clarifies that the GS rule does 

not categorically preclude injection of CO2 into any non-USDW formation types. The purpose of 

the GS rule is to ensure protection of USDWs from endangerment, and the rule requires that 

owners or operators demonstrate that wells are sited in suitable systems with geologic formations 

to receive and confine injected CO2, as required at §146.83 of the GS rule. The Class VI siting, 

well construction and operation, monitoring and testing, and post-injection site care and site 

closure requirements are designed to ensure that injected CO2 remains within the target 

formation. If an owner or operator can demonstrate to the Director's satisfaction that GS in coal 

seams, basalts, salt domes, or shales can be accomplished in a manner that protects USDWs and 

meets all of the requirements of the GS rule, the project may be permitted as a Class VI well. 

EPA acknowledges that there may be unknown risks associated with GS, particularly regarding 

GS into formations such as coal seams, basalts, and salt domes, which have been the subject of 

limited experimental projects in the past. EPA anticipates that in the short-term, GS into these 

types of formations will continue to be experimental (i.e., if they are to test GS technologies and 

collect data), and will likely be permitted as Class V experimental technology wells and be 

subject to UIC Program Guidance #83. 

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

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

address shifting of Class V experimental projects to Class VI projects and the future use of the 

59
Class V experimental technology well subclass for research and testing of new GS technologies. 

EPA acknowledges that there are limited circumstances where injection above the lowermost 

USDW can be performed in a manner that protects USDWs. 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. The waiver approach requires the submission of extensive, site-specific 

information (in conjunction with the permit application submittal) to demonstrate that injection 

of CO2 into a formation that is above or between USDWs can be done in a manner that is 

protective of USDWs. The requirements are designed to ensure 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. 

Letter ID: 0190 Comment ID: 24363 Letter Lines: 1484 to 1495 

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

USDW 

Comment: There should not be a blanket prohibition concerning injection above USDW’s or 

at specific depths. This requirement is not necessary for the protection of 

USDWs and would remove a vast number of viable formations from consideration. It 

has been shown that it is possible to operate CO2 injection wells in an EOR 

context without endangering USDWs that are located below the injection zone. An 

excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Under the proposed rule, there are other measures that 

would provide real assurance of formation integrity and require operators to 

demonstrate that their project will not endanger USDWs, making the lowermost 

USDW restriction unnecessary. Instead, operators should be able to show adequate 

containment to prevent endangerment of USDWs both above and below the injection 

zone used for geologic sequestration. 

Individual Response: As described above, EPA agrees that it is not appropriate to set a 

minimum injection depth for GS projects and the Agency believes that a determination of sitesuitability 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. 

Letter ID: 0190 Comment ID: 24364 Letter Lines: 1497 to 1509 

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

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

Comment: Rule Provision: 144.15 

60
Proposed CCS Group Recommendations: 4. Adding §144.15 to read as follows. 

§144.15 Prohibition of non-experimental Class V wells for geologic 

sequestration. 

The construction, operation or maintenance of any non-experimental Class V 

geologic sequestration well is prohibited. 

Basis for CCS Group Comments: This provision should be deleted if EPA does limit 

Class VI wells to injection below the lowermost USDW in the final rule to allow 

Directors to selectively authorize GS in areas with USDWs below the injection 

zone. 

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

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

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

are permitted, sited, constructed, operated, and closed in a manner that avoids releases of CO2 

into USDWs. 

Letter ID: 0190 Comment ID: 24365 Letter Lines: 1511 to 1515 

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

Comment: Rule Provision: 144.18 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA's rationale. 

Individual Response: EPA acknowledges the comment. For additional information on EPA's 

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

docket. 

Letter ID: 0190 Comment ID: 24366 Letter Lines: 1517 to 1528 

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

Comment Code: 5700 2.12 Comments on the proposed duration of Class VI permits (seeking 

comment) 

Comment: Rule Provision: 144.36 

Proposed CCS Group Recommendations: (a) Permits for Class I and V wells shall be 

effective for a fixed term not to exceed 10 years EXCEPT FOR WELLS USED FOR 

GEOLOGIC SEQUESTRATION. UIC Permits for Class II AND III and VI wells shall 

be issued EFFECTIVE for a period up to the operating life of the facility. 

61
PERMITS FOR CLASS VI WELLS AND FOR OTHER WELLS USED FOR GEOLOGIC 

SEQUESTRATION 

OF CO2 STREAMS SHALL BE EFFECTIVE FOR THE PERIOD THROUGH SITE 

CLOSURE. 

Basis for CCS Group Comments: Permits are necessary for geologic sequestration 

wells through the end of the post closure monitoring phase, which is consistent 

with the term site closure in the amended requirement. 

Individual Response: EPA clarifies that the final GS rule specifies that Class VI permits will be 

issued for the operating life of the facility and the post-injection site care period (144.36(a)). 

EPA believes that including the phrase "other wells used for geologic sequestration of CO2 

streams" is unnecessary, because all wells used to inject CO2 for the purpose of GS will be 

classified as Class VI wells. See also discussion in the preamble on grandfathered experimental 

Class V wells and transitioning Class II to Class VI wells. 

Letter ID: 0190 Comment ID: 24368 Letter Lines: 1549 to 1553 

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

Comment: In addition, we recommend that all GS into basalts, coal seams, and salt domes 

be conducted under Class V as experimental wells initially and then as 

commercial scale Class V wells/projects if the experimental projects demonstrate 

that these sites can be suitable for geological sequestration while preventing 

endangerment of USDWs. 

Individual Response: EPA expects that, after promulgation of the final rule, a limited number of 

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

technology associated with GS into basalts, coal seams, and salt domes. EPA clarifies that such 

projects are experimental in nature and would be to test new technologies, and that EPA does not 

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

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

Class V experimental technology wells. Such wells should be permitted as Class VI wells. 

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

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

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

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

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

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

Letter ID: 0190 Comment ID: 24369 Letter Lines: 1555 to 1571 

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

62
Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 144.51(q)(1) 

Proposed CCS Group Recommendations: (q) (1) The owner or operator of a Class I, 

II, III or VI well permitted under this part shall establish mechanical 

integrity prior to commencing injection or on a schedule determined by the 

Director. Thereafter the owner or operator of Class I, II, and III wells must 

maintain mechanical integrity as defined in §146.8 and the owner or operator of 

Class VI wells must maintain mechanical integrity as defined in §146.89 of this 

chapter. 

Basis for CCS Group Comments: EPA may want to reconsider the use of the term 

"or" as this implies that an initial MIT can be optional based on Directors 

discretion which contradicts 146.89 with respect to Class VI wells. 

Alternatively, the two provisions can be read together to require an initial MIT 

and to give the Director limited discretion to allow the scheduling of the 

initial MIT after some injection has occurred, such as may be required during 

initial testing of the well and injection zone. 

Individual Response: EPA disagrees that the suggested edit is needed, and clarifies that all 

owners or operators must demonstrate internal and external mechanical integrity prior to 

commencing injection as required at §146.87(a)(4). 

Letter ID: 0190 Comment ID: 24370 Letter Lines: 1530 to 1553 

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

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

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

Comment: Rule Provision: 144.39 

Proposed CCS Group Recommendations: THESE SECTIONS MAY REQUIRE FURTHER 

REVISIONS 

TO PROVIDE CONFORMING LANGUAGE. 

Basis for CCS Group Comments: The multi-stakeholder group has agreed that 

proposed language describing wells in classification (b)(4) establishes a 

"bright line" definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the 

current requirements of Class II. We have also agreed that the wells used for GS 

in oil and gas reservoirs that do not meet the criteria of (b)(4) should be 

subject to additional requirements. We have tentatively defined such wells as 

wells used "for geologic sequestration in oil and gas formations and where the 

criteria of paragraph (b)(4) are not met." But we have not yet attempted to 

define what specific requirements should apply to these wells. We are committed 

63
to working toward agreement on those requirements (probably within a Class II 

context) and submitting the results of that effort to EPA by February 28, 2009 

for your consideration. 

In addition, we recommend that all GS into basalts, coal seams, and salt domes 

be conducted under Class V as experimental wells initially and then as 

commercial scale Class V wells/projects if the experimental projects demonstrate 

that these sites can be suitable for geological sequestration while preventing 

endangerment of USDWs. 

Individual Response: As described above, EPA agrees that injection of CO2 for the primary 

purpose of enhancing oil and gas recovery should remain under the Class II Program. However, 

the Agency disagrees that wells injecting CO2 for the primary purpose of long-term storage 

should be regulated under Class II requirements. EPA recognizes that the oil and gas industry has 

decades of experience injecting CO2 for the purpose of EOR, and that sites used for EOR may be 

suitable for GS and may be among the first GS sites. EPA also recognizes that a by-product of 

EOR activities is that a certain percentage of the CO2 is trapped in the receiving formation. 

The Agency believes that the nature and risks of CO2 injection for the primary purpose of longterm storage pose different risks than injection for the primary purpose of ER, and therefore has 

developed new Class VI regulations to address these unique risks. For example, the volume of 

CO2 anticipated to be injected for long-term storage is significantly greater than for EOR 

operations. Reservoir pressure conditions will also be different, with Class VI injection 

operations involving large volumes of CO2 and likely having higher pressures within their 

storage formations than Class II EOR projects. 

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

CO2 into any non-USDW formation types. If an owner or operator can demonstrate to the 

Director's satisfaction that GS in coal seams, basalts, salt domes, or shales can be accomplished 

in a manner that protects USDWs and meets all of the requirements of the GS rule, the project 

may be permitted as a Class VI well. 

The Agency anticipates that, in the near-term, most GS in unmineable coal seams will continue 

to be experimental. Such projects may be permitted as Class V experimental technology wells if 

they are of an experimental nature (i.e., to test GS technologies and collect data). EPA will 

continue to review data on early GS projects, including those in unmineable coal seams, to 

determine whether the appropriate amount and types of information and documentation are 

required and being collected. 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. 

Letter ID: 0190 Comment ID: 24378 Letter Lines: 1573 to 1577 

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

Comment Code: 5900 2.14 Other administrative requirements under 40 CFR 144 

64
Comment: Rule Provision: 144.52 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

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

responses to this comment letter 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: 0190 Comment ID: 24379 Letter Lines: 1579 to 1583 

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

Comment Code: 5900 2.14 Other administrative requirements under 40 CFR 144 

Comment: Rule Provision: 144.55 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

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

responses to this comment letter 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: 0190 Comment ID: 24380 Letter Lines: 1585 to 1618 

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

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

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

Comment: Rule Provision: 144.80 

Proposed CCS Group Recommendations: (b) Class II. Classification of Wells: (b) 

Class II. Wells which inject fluids:.......(2) for enhanced recovery of oil or 

natural gas; (3) For storage of hydrocarbons.... and 

(4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC 

SEQUESTRATION IS 

OCCURRING DURING OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL 

OR NATURAL GAS 

PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE THAN 

65
INSIGNIFICANT FUTURE 

PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION 

AND (II) 

OPERATING PRESSURES ARE NO HIGHER THAN REASONABLY NECESSARY TO 

PRODUCE SUCH 

VOLUMES OR RATES; 

Basis for CCS Group Comments: EPA’s Proposal would continue to regulate and 

permit injection of CO2 for EOR/EGR purposes as Class II injection "as long as 

any production is occurring." EPA has asked for comment on the merits of this 

approach "since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted." 73 Fed. Reg. at 43502. We recommend that the rules be 

clarified to provide more certainty about the applicability of Class II 

requirements where GS of CO2 occurs in connection with EOR/EGR activities. 

Specifically, the UIC rules should provide a "bright line" definition as to the 

applicable class of wells where CO2 injection for EOR/EGR production and for GS 

occur in tandem. 

The proposed language describing wells in classification (b)(4) establishes a 

"bright line" definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the 

current requirements of Class II. We have also agreed that the wells used for GS 

in oil and gas reservoirs that do not meet the criteria of (b)(4) should be 

subject to additional requirements. 

This is the same recommendation as presented by the multi-stakeholder group, in 

which the Carbon Sequestration Council participated. 

Individual Response: As described above regarding the suggested edit at 144.6, EPA did not 

make the suggested change to 144.80. The Agency disagrees that wells injecting CO2 for the 

primary purpose of long-term storage should be regulated under Class II requirements. 

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

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

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

VI. 

Letter ID: 0190 Comment ID: 24381 Letter Lines: 1620 to 1622 

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

Comment: Rule Provision: 144.80(e) 

Proposed CCS Group Recommendations: Support the proposed language. 

66
Individual Response: EPA acknowledges the comment. For additional information on EPA's 

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

docket. 

Letter ID: 0190 Comment ID: 24382 Letter Lines: 1626 to 1666 

Comment Code: 2000 1.5 Need for a New Class of Injection Well 

Comment: Rule Provision: 144.80(f) 

Proposed CCS Group Recommendations: (f) Class VI. Wells used 

for geologic sequestration of carbon dioxide. INJECTING A CARBON 

DIOXIDE STREAM FOR GEOLOGIC SEQUESTRATION EXCEPT THOSE WELLS 

DESCRIBED IN 

SUBSECTION (B)(4) OF THIS SECTION OR OTHERWISE EXCLUDED FROM THIS 

CLASS. 

Basis for CCS Group Comments: The changes to (b) and (f) are to recognize that 

EOR can have a storage component, which is consistent with EPA’s intent as 

expressed in the preamble. It is widely recognized that CO2 based EOR can 

provide a significant early opportunity for carbon storage. As EPA correctly 

recognizes, CO2 EOR operations can have a significant storage component through 

capillary trapping or other mechanisms. Operators experience supports this 

approach as they have seen that between 1/3 to 1/2 of the injected CO2 in EOR 

operations is trapped within the receiving formation during CO2 EOR operations. 

Following abandonment of EOR operations, assuming the CO2 not trapped in the 

receiving formation, has not been produced for use in another field, essentially 

all of the CO2 that has been injected can be permanently stored. 

We recommend that all GS into basalts, coal seams, and salt domes be conducted 

under Class V as experimental wells initially and then as commercial scale Class 

V wells/projects if the experimental projects demonstrate that these sites can 

be suitable for geological sequestration while preventing endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain enough 

experience to develop suitable permitting requirements for such wells and to 

tailor those requirements at both the pilot and commercial scales until the 

agencies are ready to adapt the Class VI regulations. 

Additionally, there should not be a blanket prohibition concerning injection 

above USDW’s or at specific depths. This requirement is not necessary for the 

protection of USDWs and would remove a vast number of viable formations from 

consideration. Industry has shown that it can operate CO2 injection wells in an 

EOR context without endangering USDWs that are located below the injection zone. 

An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

67
measures that would provide real assurance of formation integrity and require 

operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. Instead, operators should be able to 

show adequate containment to prevent endangerment of USDWs both above and below 

the injection zone used for geologic sequestration. 

Individual Response: As described above regarding the suggested edit at 144.6(b), EPA did not 

make the suggested change. The Agency disagrees that wells injecting CO2 for the primary 

purpose of long-term storage should be regulated under Class II requirements. 

Regarding injection into basalts, coal seams, and salt domes, EPA clarifies that the GS rule does 

not categorically preclude injection of CO2 into any non-USDW formation types. The purpose of 

the GS rule is to ensure protection of USDWs from endangerment, and the rule requires that 

owners or operators demonstrate that wells are sited in suitable systems with geologic formations 

to receive and confine injected CO2, as required at §146.83 of the GS rule. The Class VI siting, 

well construction and operation, monitoring and testing, and post-injection site care and site 

closure requirements are designed to ensure that injected CO2 remains within the target 

formation. If an owner or operator can demonstrate to the Director's satisfaction that GS in coal 

seams, basalts, salt domes, or shales can be accomplished in a manner that protects USDWs and 

meets all of the requirements of the GS rule, the project may be permitted as a Class VI well. 

EPA acknowledges that there may be unknown risks associated with GS, particularly regarding 

GS into formations such as coal seams, basalts, and salt domes, which have been the subject of 

limited experimental projects in the past. EPA anticipates that in the short-term, GS into these 

types of formations will continue to be experimental (i.e., if they are to test GS technologies and 

collect data), and will likely be permitted as Class V experimental technology wells and be 

subject to UIC Program Guidance #83. 

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

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

address shifting of Class V experimental projects to Class VI projects and the future use of the 

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

EPA acknowledges that there are limited circumstances where injection above the lowermost 

USDW can be performed in a manner that protects USDWs. 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. The waiver approach requires the submission of extensive, site-specific 

information (in conjunction with the permit application submittal) to demonstrate that injection 

of CO2 into a formation 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. 

68
Letter ID: 0190 Comment ID: 24384 Letter Lines: 1633 to 1643 

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: Basis for CCS Group Comments: The changes to (b) and (f) are to recognize that 

EOR can have a storage component, which is consistent with EPA’s intent as 

expressed in the preamble. It is widely recognized that CO2 based EOR can 

provide a significant early opportunity for carbon storage. As EPA correctly 

recognizes, CO2 EOR operations can have a significant storage component through 

capillary trapping or other mechanisms. Operators experience supports this 

approach as they have seen that between 1/3 to 1/2 of the injected CO2 in EOR 

operations is trapped within the receiving formation during CO2 EOR operations. 

Following abandonment of EOR operations, assuming the CO2 not trapped in the 

receiving formation, has not been produced for use in another field, essentially 

all of the CO2 that has been injected can be permanently stored. 

Individual Response: As described above, EPA did not make the suggested change to 144.80. 

The Agency disagrees that wells injecting CO2 for the primary purpose of long-term storage 

should be regulated under Class II requirements. 

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

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

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

VI. 

Letter ID: 0190 Comment ID: 24385 Letter Lines: 1645 to 1653 

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

Comment: We recommend that all GS into basalts, coal seams, and salt domes be conducted 

under Class V as experimental wells initially and then as commercial scale Class 

V wells/projects if the experimental projects demonstrate that these sites can 

be suitable for geological sequestration while preventing endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain enough 

experience to develop suitable permitting requirements for such wells and to 

tailor those requirements at both the pilot and commercial scales until the 

agencies are ready to adapt the Class VI regulations. 

Individual Response: EPA expects that, after promulgation of the final rule, a limited number of 

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

technology associated with GS into basalts, coal seams, and salt domes. EPA clarifies that such 

projects are experimental in nature and would be to test new technologies, and that EPA does not 

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

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

69
Class V experimental technology wells. Such wells should be permitted as Class VI wells. 

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

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

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

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

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

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

Letter ID: 0190 Comment ID: 24386 Letter Lines: 1655 to 1666 

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

USDW 

Comment: Additionally, there should not be a blanket prohibition concerning injection 

above USDW’s or at specific depths. This requirement is not necessary for the 

protection of USDWs and would remove a vast number of viable formations from 

consideration. Industry has shown that it can operate CO2 injection wells in an 

EOR context without endangering USDWs that are located below the injection zone. 

An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

measures that would provide real assurance of formation integrity and require 

operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. Instead, operators should be able to 

show adequate containment to prevent endangerment of USDWs both above and below 

the injection zone used for geologic sequestration. 

Individual Response: As described above, 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. 

Letter ID: 0190 Comment ID: 24387 Letter Lines: 1668 to 1672 

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

Comment Code: 5900 2.14 Other administrative requirements under 40 CFR 144 

Comment: Rule Provision: Part 146 (12) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

70
Individual Response: EPA acknowledges the comment. Please see the remainder of EPA's 

responses to this comment letter 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: 0190 Comment ID: 24388 Letter Lines: 1674 to 1701 

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

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

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

Comment: Rule Provision: 146.5(f) 

Proposed CCS Group Recommendations: (b) Class II. Classification of Wells: (b) 

Class II. Wells which inject fluids:.......(2) for enhanced recovery of oil or 

natural gas; (3) For storage of hydrocarbons..... and 

(4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC 

SEQUESTRATION IS 

OCCURRING DURING OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL 

OR NATURAL GAS 

PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE THAN 

INSIGNIFICANT FUTURE 

PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION 

AND (II) 

OPERATING PRESSURES ARE NO HIGHER THAN REASONABLY NECESSARY TO 

PRODUCE SUCH 

VOLUMES OR RATES; 

Basis for CCS Group Comments: EPA’s Proposal would continue to regulate and 

permit injection of CO2 for EOR/EGR purposes as Class II injection "as long as 

any production is occurring." EPA has asked for comment on the merits of this 

approach "since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted." 73 Fed. Reg. at 43502. We recommend that the rules be 

clarified to provide more certainty about the applicability of Class II 

requirements where GS of CO2 occurs in connection with EOR/EGR activities. 

Specifically, the UIC rules should provide a "bright line" definition as to the 

applicable class of wells where CO2 injection for EOR/EGR production and for GS 

occur in tandem. 

The proposed language describing wells in classification (b)(4) establishes a 

"bright line" definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the 

Individual Response: As described above, EPA did not make the suggested change. The 

71
Agency disagrees that wells injecting CO2 for the primary purpose of long-term storage should 

be regulated under Class II requirements. 

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

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

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

VI. 

The Agency believes that the nature and risks of CO2 injection for the primary purpose of longterm storage pose different risks than injection for the primary purpose of ER, and therefore has 

developed new Class VI regulations to address these unique risks. For example, the volume of 

CO2 anticipated to be injected for long-term storage is significantly greater than for ER 

operations. Reservoir pressure conditions will also be different, with Class VI injection 

operations involving large volumes of CO2 and likely having higher pressures within their 

storage formations than Class II ER projects. 

Letter ID: 0190 Comment ID: 24389 Letter Lines: 1709 to 1714 

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

Comment Code: 5900 2.14 Other administrative requirements under 40 CFR 144 

Comment: Rule Provision: 146.5(e) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

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

responses to this comment letter 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: 0190 Comment ID: 24390 Letter Lines: 1715 to 1756 

Comment Code: 2000 1.5 Need for a New Class of Injection Well 

Comment: Rule Provision: 146.5(f) 

Proposed CCS Group Recommendations: (f) Class VI. Wells used 

for geologic sequestration of carbon dioxide beneath the lowermost formation 

containing an underground source of drinking water (USDW). INJECTING A CARBON 

DIOXIDE STREAM FOR GEOLOGIC SEQUESTRATION EXCEPT THOSE WELLS 

DESCRIBED IN 

SUBSECTION (B)(4) OF THIS SECTION OR OTHERWISE EXCLUDED FROM THIS 

72
CLASS. 

Basis for CCS Group Comments: The changes to (b) and (f) are to recognize that 

EOR can have a storage component, which is consistent with EPA’s intent as 

expressed in the preamble. It is widely recognized that CO2 based EOR can 

provide a significant early opportunity for carbon storage. As EPA correctly 

recognizes, CO2 EOR operations can have a significant storage component through 

capillary trapping or other mechanisms. Operators experience supports this 

approach as they have seen that between 1/3 to 1/2 of the injected CO2 in EOR 

operations is trapped within the receiving formation during CO2 EOR operations. 

Following abandonment of EOR operations, assuming the CO2 not trapped in the 

receiving formation, has not been produced for use in another field, essentially 

all of the CO2 that has been injected can be permanently stored. 

We recommend that all GS into basalts, coal seams, and salt domes be conducted 

under Class V as experimental wells initially and then as commercial scale Class 

V wells/projects if the experimental projects demonstrate that these sites can 

be suitable for geological sequestration while preventing endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain enough 

experience to develop suitable permitting requirements for such wells and to 

tailor those requirements at both the pilot and commercial scales until the 

agencies are ready to adapt the Class VI regulations. 

Additionally, there should not be a blanket prohibition concerning injection 

above USDW’s or at specific depths. This requirement is not necessary for the 

protection of USDWs and would remove a vast number of viable formations from 

consideration. Industry has shown that it can operate CO2 injection wells in an 

EOR context without endangering USDWs that are located below the injection zone. 

An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

measures that would provide real assurance of formation integrity and require 

operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. Instead, operators should be able to 

show adequate containment to prevent endangerment of USDWs both above and below 

the injection zone used for geologic sequestration. 

Individual Response: As described above regarding the suggested edit at 144.6(b), EPA did not 

make the suggested change. The Agency disagrees that wells injecting CO2 for the primary 

purpose of long-term storage should be regulated under Class II requirements. 

Regarding injection into basalts, coal seams, and salt domes, EPA clarifies that the GS rule does 

not categorically preclude injection of CO2 into any non-USDW formation types. The purpose of 

the GS rule is to ensure protection of USDWs from endangerment, and the rule requires that 

owners or operators demonstrate that wells are sited in suitable systems with geologic formations 

to receive and confine injected CO2, as required at §146.83 of the GS rule. The Class VI siting, 

73
well construction and operation, monitoring and testing, and post-injection site care and site 

closure requirements are designed to ensure that injected CO2 remains within the target 

formation. If an owner or operator can demonstrate to the Director's satisfaction that GS in coal 

seams, basalts, salt domes, or shales can be accomplished in a manner that protects USDWs and 

meets all of the requirements of the GS rule, the project may be permitted as a Class VI well. 

EPA acknowledges that there may be unknown risks associated with GS, particularly regarding 

GS into formations such as coal seams, basalts, and salt domes, which have been the subject of 

limited experimental projects in the past. EPA anticipates that in the short-term, GS into these 

types of formations will continue to be experimental (i.e., if they are to test GS technologies and 

collect data), and will likely be permitted as Class V experimental technology wells and be 

subject to UIC Program Guidance #83. 

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

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

address shifting of Class V experimental projects to Class VI projects and the future use of the 

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

EPA acknowledges that there are limited circumstances where injection above the lowermost 

USDW can be performed in a manner that protects USDWs. 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. The waiver approach requires the submission of extensive, site-specific 

information (in conjunction with the permit application submittal) to demonstrate that injection 

of CO2 into a formation 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. 

Letter ID: 0190 Comment ID: 24391 Letter Lines: 1723 to 1733 

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: Basis for CCS Group Comments: The changes to (b) and (f) are to recognize that 

EOR can have a storage component, which is consistent with EPA’s intent as 

expressed in the preamble. It is widely recognized that CO2 based EOR can 

provide a significant early opportunity for carbon storage. As EPA correctly 

recognizes, CO2 EOR operations can have a significant storage component through 

capillary trapping or other mechanisms. Operators experience supports this 

approach as they have seen that between 1/3 to 1/2 of the injected CO2 in EOR 

operations is trapped within the receiving formation during CO2 EOR operations. 

Following abandonment of EOR operations, assuming the CO2 not trapped in the 

receiving formation, has not been produced for use in another field, essentially 

all of the CO2 that has been injected can be permanently stored. 

74
Individual Response: As described above regarding the suggested edit at 144.6, EPA did not 

make the suggested change. The Agency acknowledge that some CO2 stays trapped in the 

formation, but disagrees that wells injecting CO2 for the primary purpose of long-term storage 

should be regulated under Class II requirements. 

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

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

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

VI. 

Letter ID: 0190 Comment ID: 24392 Letter Lines: 1735 to 1743 

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

Comment: We recommend that all GS into basalts, coal seams, and salt domes be conducted 

under Class V as experimental wells initially and then as commercial scale Class 

V wells/projects if the experimental projects demonstrate that these sites can 

be suitable for geological sequestration while preventing endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain enough 

experience to develop suitable permitting requirements for such wells and to 

tailor those requirements at both the pilot and commercial scales until the 

agencies are ready to adapt the Class VI regulations. 

Individual Response: EPA expects that, after promulgation of the final rule, a limited number of 

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

technology associated with GS into basalts, coal seams, and salt domes. EPA clarifies that such 

projects are experimental in nature and would be to test new technologies, and that EPA does not 

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

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

Class V experimental technology wells. Such wells should be permitted as Class VI wells. 

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

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

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

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

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

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

Letter ID: 0190 Comment ID: 24393 Letter Lines: 1745 to 1756 

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

USDW 

75
Comment: Additionally, there should not be a blanket prohibition concerning injection 

above USDW’s or at specific depths. This requirement is not necessary for the 

protection of USDWs and would remove a vast number of viable formations from 

consideration. Industry has shown that it can operate CO2 injection wells in an 

EOR context without endangering USDWs that are located below the injection zone. 

An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

measures that would provide real assurance of formation integrity and require 

operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. Instead, operators should be able to 

show adequate containment to prevent endangerment of USDWs both above and below 

the injection zone used for geologic sequestration. 

Individual Response: As described above, 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. 

Letter ID: 0190 Comment ID: 24394 Letter Lines: 1758 to 1762 

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

Comment: Rule Provision: 146, Subpart H, List of Headings 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. For additional information on EPA's 

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

docket. 

Letter ID: 0190 Comment ID: 24395 Letter Lines: 1764 to 1787 

Comment Code: 2000 1.5 Need for a New Class of Injection Well 

Comment: Rule Provision: 146.81(a) 

Proposed CCS Group Recommendations: THESE SECTIONS MAY REQUIRE FURTHER 

REVISIONS 

TO PROVIDE CONFORMING LANGUAGE. 

Basis for CCS Group Comments: The multi-stakeholder group has agreed that 

proposed language describing wells in classification (b)(4) establishes a 

76
"bright line" definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the 

current requirements of Class II. We have also agreed that the wells used for GS 

in oil and gas reservoirs that do not meet the criteria of (b)(4) should be 

subject to additional requirements. We have tentatively defined such wells as 

wells used "for geologic sequestration in oil and gas formations and where the 

criteria of paragraph (b)(4) are not met." But we have not yet attempted to 

define what specific requirements should apply to these wells. We are committed 

to working toward agreement on those requirements (probably within a Class II 

context) and submitting the results of that effort to EPA by February 28, 2009 

for your consideration. 

In addition, we recommend that all GS into basalts, coal seams, and salt domes 

be conducted under Class V as experimental wells initially and then as 

commercial scale Class V wells/projects if the experimental projects demonstrate 

that these sites can be suitable for geological sequestration while preventing 

endangerment of USDWs. 

Individual Response: As described above, EPA agrees that injection of CO2 for the primary 

purpose of enhancing oil and gas recovery should remain under the Class II Program. However, 

the Agency disagrees that wells injecting CO2 for the primary purpose of long-term storage 

should be regulated under Class II requirements. EPA recognizes that the oil and gas industry has 

decades of experience injecting CO2 for the purpose of EOR, and that sites used for EOR may be 

suitable for GS and may be among the first GS sites. EPA also recognizes that a by-product of 

EOR activities is that a certain percentage of the CO2 is trapped in the receiving formation. 

The Agency believes that the nature and risks of CO2 injection for the primary purpose of longterm storage pose different risks than injection for the primary purpose of ER, and therefore has 

developed new Class VI regulations to address these unique risks. For example, the volume of 

CO2 anticipated to be injected for long-term storage is significantly greater than for EOR 

operations. Reservoir pressure conditions will also be different, with Class VI injection 

operations involving large volumes of CO2 and likely having higher pressures within their 

storage formations than Class II EOR projects. 

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

CO2 into any non-USDW formation types. If an owner or operator can demonstrate to the 

Director's satisfaction that GS in coal seams, basalts, salt domes, or shales can be accomplished 

in a manner that protects USDWs and meets all of the requirements of the GS rule, the project 

may be permitted as a Class VI well. 

The Agency anticipates that, in the near-term, most GS in unmineable coal seams will continue 

to be experimental. Such projects may be permitted as Class V experimental technology wells if 

they are of an experimental nature (i.e., to test GS technologies and collect data). EPA will 

continue to review data on early GS projects, including those in unmineable coal seams, to 

determine whether the appropriate amount and types of information and documentation are 

required and being collected. EPA plans, every six years, to collect and review data on GS 

77
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: 0190 Comment ID: 24396 Letter Lines: 1769 to 1781 

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: Basis for CCS Group Comments: The multi-stakeholder group has agreed that 

proposed language describing wells in classification (b)(4) establishes a 

"bright line" definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the 

current requirements of Class II. We have also agreed that the wells used for GS 

in oil and gas reservoirs that do not meet the criteria of (b)(4) should be 

subject to additional requirements. We have tentatively defined such wells as 

wells used "for geologic sequestration in oil and gas formations and where the 

criteria of paragraph (b)(4) are not met." But we have not yet attempted to 

define what specific requirements should apply to these wells. We are committed 

to working toward agreement on those requirements (probably within a Class II 

context) and submitting the results of that effort to EPA by February 28, 2009 

for your consideration. 

Individual Response: As described above, EPA believes that injection for the primary purpose 

of long-term storage is sufficiently different from Class II ER operations and warrants tailored 

requirements. For example, the volume of CO2 anticipated to be injected in Class VI wells is 

significantly greater than for Class II wells. Reservoir pressure conditions will also be different, 

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

pressures within their storage formations than Class II ER projects. 

EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas recovery 

should remain under the Class II Program. EPA believes that there are significant differences 

between how projects are operated, as well as the risks posed by these different injection 

activities. The new tailored approach of the GS rule was designed to address the general risks 

deep injection may pose to USDWs and was tailored specifically to address the risks posed by 

long-term storage of CO2 (i.e., very large volumes, very long time-periods, and reservoir 

pressure conditions). 

EPA is developing guidance on transitioning permits from Class II to Class VI. The guidance 

will assist Directors in determining whether an injection project should be transitioned from 

Class II where the primary purpose is oil and gas production to Class VI where the primary 

purpose is long-term storage of large volumes of CO2. The guidance describes the recommended 

methods the Director may use to evaluate changes in risk to USDWs from projects, and how the 

Director may determine whether a project should be regulated within the Class II or Class VI 

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

78
http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. For more information, please 

see the discussion on transition of Class II wells in the preamble to the final GS rule. 

Letter ID: 0190 Comment ID: 24397 Letter Lines: 1783 to 1787 

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

Comment: In addition, we recommend that all GS into basalts, coal seams, and salt domes 

be conducted under Class V as experimental wells initially and then as 

commercial scale Class V wells/projects if the experimental projects demonstrate 

that these sites can be suitable for geological sequestration while preventing 

endangerment of USDWs. 

Individual Response: EPA expects that, after promulgation of the final rule, a limited number of 

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

technology associated with GS into basalts, coal seams, and salt domes. EPA clarifies that such 

projects are experimental in nature and would be to test new technologies, and that EPA does not 

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

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

Class V experimental technology wells. Such wells should be permitted as Class VI wells. 

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

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

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

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

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

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

Letter ID: 0190 Comment ID: 24398 Letter Lines: 1789 to 1801 

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

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

Comment: Rule Provision: 146.81(b) 

Proposed CCS Group Recommendations: (b) This subpart applies to wells used to 

inject carbon dioxide EXCLUSIVELY for the purpose of geologic sequestration, 

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

dioxide stream in subsurface geologic formations OTHER THAN OIL OR GAS 

RESERVOIRS, COAL SEAMS, BASALTS, OR SALT CAVERNS. 

Basis for CCS Group Comments: See 144.6 and the note immediately above about the 

requirement for conforming language. 

79
Deleted "gaseous, liquid or supercritical" because it was added to the 

definition of CO2 stream. 

Individual Response: As described above, EPA expects that, after promulgation of the final 

rule, a limited number of experimental injection projects to test GS technology will continue, 

e.g., to inform the technology associated with GS into basalts, coal seams, and salt domes. Based 

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

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

further discussion on EPA's final approach. 

Letter ID: 0190 Comment ID: 24399 Letter Lines: 1803 to 1823 

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

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

Comment: Rule Provision: 146.81(c) 

Proposed CCS Group Recommendations: (c) This subpart applies to owners and 

operators of permit or rule-authorized Class I industrial, Class II WHICH HAVE 

CEASED AND WILL NO LONGER BE USED FOR ENHANCED RECOVERY OF OIL OR 

NATURAL GAS, 

or Class V experimental carbon dioxide injection projects who seek to apply for 

a Class VI geologic sequestration permit for their well or wells. If the 

Director determines that USDWs will not be endangered, such wells are exempt, at 

the Director’s discretion, from the casing and cementing requirements at §§ 

146.86(b) and 146.87(a)(1) through (3). CLASS VI REQUIREMENTS OF SUBPART H OF 

THIS PART. WELLS CONSTRUCTED IN ACCORDANCE WITH THE CLASS II 

REQUIREMENTS OF § 

146.22 AND USED IN CO2 SERVICE AND THAT HAVE DEMONSTRATED MIT ARE 

EXEMPT FROM THE 

REQUIREMENTS AT §§146.86 AND 146.87. 

Basis for CCS Group Comments: For first part, see 144.6 and the note above about 

the requirement for conforming language. 

Added language for transition of Class II wells to Class VI operations. These 

wells should be allowed based on their history of sound performance under the 

Class II program as demonstrated by MIT results. The language also allows the 

Director to exercise discretion to exempt other Class VI requirements. 

Individual Response: EPA disagrees that other requirements (e.g., monitoring, operational, and 

AoR requirements) should also be grandfathered. Following re-permitting of the project as GS, 

many of the unique factors of GS sites (e.g., increased reservoir pressures associated with large 

volumes of stored CO2 and the corrosivity of CO2 in the presence of water) will result in an 

increased risk profile, warranting the specific requirements in the final GS rule. Following repermitting as Class VI wells, these projects must be subject to the operational, MIT, monitoring, 

80
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: 0190 Comment ID: 24400 Letter Lines: 1825 to 1837 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 3200 2.2 Proposed Area of Review and Corrective Action Requirements (40 

CFR 146.84) 

Comment: Rule Provision: 146.81(d) [Definition - Area of review] 

Proposed CCS Group Recommendations: Area of review means the region 

surrounding the geologic sequestration project that may be impacted by the 

injection activity. The area of review is based on computational modeling that 

accounts for the physical and chemical properties of all phases of the injected 

carbon dioxide stream. SUBSURFACE THREE-DIMENSIONAL EXTENT OF THE CARBON 

DIOXIDE PLUME, ASSOCIATED PRESSURE FRONT, AS WELL AS THE OVERLYING 

FORMATIONS 

AND SURFACE AREA ABOVE THAT DELINEATED REGION. 

Basis for CCS Group Comments: Defining the AOR based on the extent of the CO2 

plume and its associated pressure front is a more direct approach, rather than 

the approach offered by the EPA. 

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

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

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

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

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

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

subsurface storage site and the AoR. Although EPA disagrees with the commenter's suggested 

change, the Agency has carefully considered all comments on the AoR definition at 146.84(a) 

and modified it to read as follows: The region surrounding the geologic sequestration project 

where USDWs may be endangered by the injection activity. The area of review is delineated 

using computational modeling that accounts for the physical and chemical properties of all 

phases of the injected CO2 stream and is based on available site characterization, monitoring, 

and operational data. EPA believes that this definition is sufficiently broad and describes both 

the intent of the computational modeling and the relationship of the AoR to areas that are subject 

to the risks associated with injection. 

Letter ID: 0190 Comment ID: 24401 Letter Lines: 1839 to 1853 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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

81
Comment: Rule Provision: 146.81(d) [Definition - Carbon dioxide stream] 

Proposed CCS Group Recommendations: Carbon dioxide stream means carbon dioxide, 

IN ANY PHYSICAL STATE OR FORM, AND ANY ASSOCIATED substances derived from 

the 

that has been captured from an emission source (e.g., a power plant), plus 

incidental associated substances derived from the source materials and the 

capture process, and any OR ITS PROCESSING, AND substances added to enable or 

improve the injection process. This subpart does not apply to any carbon dioxide 

stream that meets the definition of a hazardous waste under 40 CFR part 261. 

Basis for CCS Group Comments: Source of CO2 is not an issue in the context of 

defining the CO2 stream. The rule applies to the injection of CO2 and should not 

address the origins of the materials since that is beyond the scope of this 

regulation. Original text would have precluded injection of CO2 from some 

sources. 

Individual Response: The final GS rule retains the definition of a CO2 stream as proposed. The 

GS regulation applies to injection of CO2 for the purpose of GS, regardless of the source of the 

CO2. It is beyond the scope of the GS rule and the UIC Program’s authority to require or set 

standards for upstream generators of CO2 or purification facilities. For purposes of GS, the UIC 

program’s authority under the SDWA is limited to ensuring that GS projects are sited, 

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

Although the GS regulation does not apply to the source of CO2 streams, the GS rule, at 

§146.82(a)(7)(iv), requires the owner or operator to submit data about the site, including an 

analysis of the chemical and physical characteristics of the CO2 stream because the 

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

facility, coal composition, plant operating conditions, and pollution removal technologies. 

Letter ID: 0190 Comment ID: 24402 Letter Lines: 1855 to 1865 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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

Comment: Rule Provision: 146.81(d) [Definition - Confining zone] 

Proposed CCS Group Recommendations: Confining zone means a geological formation, 

group of formations, or part of a formation THAT IS CAPABLE OF LIMITING FLUID 

MOVEMENT FROM AN INJECTION ZONE. 

Basis for CCS Group Comments: The current UIC program definition of confining 

zone is preferable to the proposed definition. There are no special 

circumstances for CO2 streams that warrant a change. In addition, the word 

"above" should be changed to "from" to accommodate situations where USDWs may be 

82
beneath as well as above the injection zone. 

Individual Response: EPA did not change the requirement that injection occur below the 

lowermost USDW. However, the final GS rule contains a provision (at §146.95) for owners or 

operators to apply for waivers from the requirement that injection be 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: 0190 Comment ID: 24403 Letter Lines: 1867 to 1871 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 3400 2.2.2 Corrective Action 

Comment: Rule Provision: 146.81(d) [Definition - Corrective action] 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the commenter’s support; the final GS rule retains the 

definition. 

Letter ID: 0190 Comment ID: 24404 Letter Lines: 1873 to 1881 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: Rule Provision: 146.81(d) [Definition - Geologic sequestration] 

Proposed CCS Group Recommendations: Geologic sequestration means the long-term 

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

subsurface geologic formations. This term does not apply to its capture or 

transport. 

Basis for CCS Group Comments: Added to definition of carbon dioxide stream, so 

not needed here. 

Individual Response: EPA disagrees with the suggested edit. However, the Agency has 

modified the definition of geologic sequestration at §146.81(d) to read as follows: “[T]he longterm containment of a gaseous, liquid, or supercritical carbon dioxide stream in subsurface 

geologic formations. This term does not apply to carbon dioxide capture or transport.” 

The final definition of carbon dioxide stream also remains unchanged. Carbon dioxide stream is 

defined at §146.81(d) as: “[C]arbon dioxide that has been captured from an emission source 

(e.g., a power plant), plus incidental associated substances derived from the source materials and 

83
the capture process, and any substances added to the stream to enable or improve the injection 

process. This subpart does not apply to any carbon dioxide stream that meets the definition of a 

hazardous waste under 40 CFR part 261.” 

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

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

final rule and preamble for additional information. 

Letter ID: 0190 Comment ID: 24405 Letter Lines: 1883 to 1901 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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

USDW 

Comment: Rule Provision: 146.81(d) [Definition - Geologic sequestration project] 

Proposed CCS Group Recommendations: Geologic sequestration project means an 

injection well or wells used to emplace a carbon dioxide stream beneath the 

lowermost formation containing a USDW INTO AN INJECTION ZONE EXCLUSIVELY FOR 

THE PURPOSE OF GEOLOGIC SEQUESTRATION. It includes the subsurface threedimensional extent of the carbon dioxide plume, associated pressure front, and 

displaced brine, as well as the surface area above that delineated region. 

Basis for CCS Group Comments: There should not be a blanket prohibition 

concerning injection above USDW’s or at specific depths. This requirement is not 

necessary for the protection of USDWs and would remove a vast number of viable 

formations from consideration. Industry has shown that it can operate CO2 

injection wells in an EOR context without endangering USDWs that are located 

below the injection zone. An excellent example is the Salt Creek EOR project in 

Wyoming, which has a USDW below the injection zone. Moreover, under the proposed 

rule, there are other measures that would provide real assurance of formation 

integrity and require operators to demonstrate that their project will not 

endanger USDWs, making the lowermost USDW restriction unnecessary. 

Individual Response: EPA has revised the definition of a geologic sequestration project to 

account for the new requirements to include “wells used for geologic sequestration of carbon 

dioxide that have been granted a waiver of the injection depth requirements pursuant to 

requirements at §146.95.” 

Letter ID: 0190 Comment ID: 24406 Letter Lines: 1903 to 1913 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: Rule Provision: 146.81(d) [Definition - Injection zone] 

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Proposed CCS Group Recommendations: Injection zone means a geologic formation, 

group of formations, or part of a formation that is of sufficient areal 

extent, thickness, porosity, and permeability to receive carbon dioxide 

RECEIVING FLUIDS through a well or wells associated with a geologic 

sequestration project 

Basis for CCS Group Comments: Existing definition in the CFR is sufficient and 

does not need to be changed. Furthermore, adding the sufficiency requirement is 

not a definitional issue and should be dealt with elsewhere. 

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

zone at §146.81(d) is unchanged and reads as follows: “[A] geologic formation, group of 

formations, or part of a formation that is of sufficient areal extent, thickness, porosity, and 

permeability to receive carbon dioxide through a well or wells associated with a geologic 

sequestration project.” 

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

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

final rule and preamble for additional information. 

Letter ID: 0190 Comment ID: 24407 Letter Lines: 1915 to 1924 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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

Comment: Rule Provision: 146.81(d) [Definition - Post-injection site care] 

Proposed CCS Group Recommendations: Post-injection site care means 

appropriate monitoring and other actions (including corrective action) 

needed following cessation of injection to assure that USDWs are not 

endangered, AS REQUIRED UNDER §146.93. 

Basis for CCS Group Comments: Deleted "appropriate" because the definition of it 

is not clear. Deleted USDW phrase because it is incorporated in 146 

requirements. 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

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

the final rule and preamble for further discussion on EPA's final approach. EPA adds that all 

post-injection site care must be performed pursuant to the post-injection site care and site closure 

plan, which must be approved by the Director and demonstrated to include monitoring activities 

that protect USDWs from endangerment. 

Letter ID: 0190 Comment ID: 24408 Letter Lines: 1926 to 1935 

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Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: Rule Provision: 146.81(d) [Definition - Pressure front] 

Proposed CCS Group Recommendations: Pressure front means the zone of elevated 

pressure that is created by the injection of the carbon dioxide STREAM into the 

subsurface, For the purposes of this subpart, the pressure front of a carbon 

dioxide plume refers to a zone where there is a pressure differential 

sufficient to cause movement of injected fluids THE CARBON DIOXIDE STREAM or 

formation fluids FROM THE INJECTION ZONE into a USDW. 

Basis for CCS Group Comments: Clarification. 

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

front at §146.81(d) remains unchanged, and reads as follows: “[T]he zone of elevated pressure 

that is created by the injection of carbon dioxide into the subsurface. For the purposes of this 

subpart, the pressure front of a carbon dioxide plume refers to a zone where there is a pressure 

differential sufficient to cause the movement of injected fluids or formation fluids into a 

USDW.” 

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

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

final rule and preamble for additional information. 

Letter ID: 0190 Comment ID: 24409 Letter Lines: 1937 to 1944 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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

Comment: Rule Provision: 146.81(d) [Definition - Site closure] 

Proposed CCS Group Recommendations: Site closure MEANS the point/time, as 

determined by the Director following the requirements under §146.93, at which 

the owner or operator of a GS site PROJECT is released from post-injection 

site care responsibilities. 

Basis for CCS Group Comments: "GS project" is consistent with other definitions. 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

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

the final rule and preamble for further discussion on EPA's final approach. 

Letter ID: 0190 Comment ID: 24410 Letter Lines: 1946 to 1955 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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

Comment: Rule Provision: 146.81(d) [Definition - transmissible fault or fracture] 

Proposed CCS Group Recommendations: transmissible fault or fracture means a fault 

or fracture that has sufficient permeability and vertical extent to allow fluids 

to move between formations BEYOND THE CONFINING ZONE. 

Basis for CCS Group Comments: The term "between formations" is inaccurate since 

there can be multiple formations within an injection zone. The critical factor 

for transmissivity is movement of injected or displaced fluids beyond the 

confining zone. 

Individual Response: EPA has retained the proposed definition, which is the same as the 

existing definition at §148.2, to address transmissive faults and fractures that extend beyond the 

confining zone. 

Letter ID: 0190 Comment ID: 24411 Letter Lines: 1957 to 1961 

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

Comment: Rule Provision: 146.82 [Introductory text] 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. For additional information on EPA's 

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

docket. 

Letter ID: 0190 Comment ID: 24412 Letter Lines: 1963 to 1967 

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

Comment: Rule Provision: 146.82(a) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. For additional information on EPA's 

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

docket. 

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Letter ID: 0190 Comment ID: 24413 Letter Lines: 1969 to 1988 

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

Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provision: 146.82(b) 

Proposed CCS Group Recommendations: (b) A SURFACE map showing the PROPOSED 

LOCATIONS FOR the injection well(s) for which a permit is sought and the 

applicable area of review. Within the area of review, the map must show the 

number, or name and location of all KNOWN injection wells, producing wells, 

abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, State 

or EPA approved subsurface cleanup sites, surface bodies of water, springs, 

mines (surface and subsurface), quarries, water wells and other pertinent 

surface features including structures intended for human occupancy and roads. 

The map should also show faults, if known or suspected. Only information of 

public record is required to be included on this map; 

Basis for CCS Group Comments: Faults are not shown on maps unless there is a 

surface expression of the fault. Also, faults are detailed in (d) below and this 

language appears redundant. 

The word "known" needs to be added to remove any implication that an applicant 

has to conduct studies to determine the location of wells that are not currently 

documented in some fashion. 

Individual Response: EPA disagrees that information submitted with Class VI permit 

applications should be limited to known (i.e., previously available) data. Site-specific conditions 

may affect the suitability of a proposed site. Therefore the owner or operator must provide to the 

Director the necessary preliminary information to support a permit decision. 

EPA did not delete “faults” from §146.82(b) because faults may have surface expressions, which 

should be presented on submitted maps in order to complement the required cross-section data. 

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

and Directors in evaluating permit requirements and applications under §146.82. The guidance 

provides recommendations regarding characterizing the regional geology and hydrogeology of a 

proposed GS site as well as performing the necessary geochemical, geomechanical, and 

geophysical analyses of the injection and confining zone. The guidance can be found on EPA’s 

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

final rule and the discussion of geologic site characterization in the preamble for additional 

information. 

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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 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. EPA 

acknowledges that some smaller fractures may not be detectable during the site characterization 

process, and clarifies that §146.82(a)(3)(ii) requires the owner or operator to submit data on 

known or suspected faults and fractures (i.e., not all fractures). 

Letter ID: 0190 Comment ID: 24414 Letter Lines: 1990 to 1999 

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

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

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provision: 146.82(c) 

Proposed CCS Group Recommendations: (c) A MAP DELINEATING the area of review 

based on UPON modeling, using ALL AVAILABLE data INCLUDING DATA obtained 

during logging and testing of the well and the formation as required by 

paragraphs (l), (r), and (s) of this section ANY WELLS IN THE AREA OF REVIEW 

Basis for CCS Group Comments: This appears to be related to a condition where a 

well is already drilled. This does not align with requesting information to 

receive a permit. 

Individual Response: EPA agrees that not all of the information listed at §146.82 of the 

proposed regulation will be available at the time the owner or operator develops their initial 

permit application. In response to comments and based on an evaluation of the proposed 

requirements at §146.82, the Agency revised this subpart so that the final regulation specifies 

separate requirements for information to be submitted with the permit application and before 

well construction is approved (at §146.82(a)) and information to be submitted before operation 

of the well is authorized (at §146.82(c)). 

EPA believes that this revision of §146.82 addresses commenters' concerns regarding the timing 

of information to be submitted. In addition, section §146.82 in the final rule is similar to the 

permit application requirements for other injection well classes, which could help avoid 

confusion about how to meet the permitting requirements for Class VI wells. The requirements at 

§146.82(c) for information to be submitted before operation of the well is authorized are very 

similar to those for Class I wells, with modifications and additions that address the unique 

challenges and types of data collected for GS wells. 

The requirement to provide the final area of review based on modeling and data obtained during 

89
logging and testing is in the final GS rule at §146.82(c)(1). Please see the final rule and the 

discussion of geologic site characterization in the preamble for additional information. 

Letter ID: 0190 Comment ID: 24415 Letter Lines: 2001 to 2023 

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

Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provision: 146.82(d) 

Proposed CCS Group Recommendations: (d) KNOWN information on the geologic 

structure and hydrogeologic RESERVOIR properties of the proposed storage 

site and overlying formations, including: 

(1) ISOPACH maps and OF THE PROPOSED INJECTION AND CONFINING ZONE(S), A 

STRUCTURAL CONTOUR MAP HUNG ON THE TOP OF THE PROPOSED INJECTION 

ZONE, AND AT 

LEAST TWO GEOLOGIC cross sections of the area of review SHOWING THE GEOLOGIC 

FORMATIONS FROM THE SURFACE TO TOTAL DEPTH. 

(2) Location, orientation, and properties of known or suspected SUBSURFACE 

faults and fractures that may transect the confining zone(s) in the area of 

review and a determination that they would not interfere with containment; 

Basis for CCS Group Comments: If the information is not known, it cannot be 

reported. 

"Reservoir" and changes to (1) and (2) are technical corrections. 

Fractures generally can't be identified until a well is drilled and evaluated. 

Even then, only fractures in the immediate vicinity of the well bore can be 

identified. 

Individual Response: EPA acknowledges that some smaller fractures may not be detectable 

during the site characterization process, and clarifies that §146.82(a)(3)(ii) requires the owner or 

operator to submit data on known or suspected faults and fractures (i.e., not all fractures). Other 

requirements for GS injection wells and sites can mitigate the potential impacts of unidentified 

fractures. These include limitations on injection pressures to avoid propagation of existing 

fractures in the confining zone (§146.88(a)), collection and assessments of CO2 monitoring data 

at the site, and AoR reevaluations (§146.84(e)) to assess possible CO2 movement through highpermeability regions (i.e., faults and/or fractures) not detected in the initial site characterization. 

As described above, EPA disagrees that information submitted with Class VI permit applications 

90
should be limited to known (i.e., previously available) data. Site-specific conditions may affect 

the suitability of a proposed site. Therefore the owner or operator must provide to the Director 

the necessary preliminary information to support a permit decision. Please see the final rule and 

the discussion of geologic site characterization in the preamble for additional information. 

Letter ID: 0190 Comment ID: 24416 Letter Lines: 2025 to 2033 

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

Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provision: 146.82(d)(3) 

Proposed CCS Group Recommendations: (3) Information on seismic history THAT HAVE 

AFFECTED THE PROPOSED AREA OF REVIEW, INCLUDING KNOWLEDGE OF 

PREVIOUS SEISMIC 

EVENTS, including the presence and depth of seismic sources and a determination 

that the seismicity would not interfere with containment; 

Basis for CCS Group Comments: Information on seismic history should have some 

degree of relevance to the project. 

Individual Response: EPA believes that consideration of local and regional seismicity is 

important and this type of review is relevant to every project. The site characterization provisions 

in the GS rule, including a review of the local and regional geology, and detailed review of any 

known or potential seismically active terrain in the vicinity of a proposed GS site, are necessary 

to minimize the potential for induced seismic events or the reactivation of faults, which are a 

known potential risk associated with underground injection and are addressed in all aspects of 

the UIC regulations. 

Letter ID: 0190 Comment ID: 24417 Letter Lines: 2035 to 2049 

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

Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provision: 146.82(d)(4) 

Proposed CCS Group Recommendations: (4) Data SUFFICIENT TO DEMONSTRATE THE 

EFFECTIVENESS OF THE INJECTION AND CONFINING ZONE(S), INCLUDING DATA 

ON THE 

91
DEPTH, AREAL EXTENT, THICKNESS, MINERALOGY, POROSITY, VERTICAL 

PERMEABILITY 

RESERVOIR PRESSURE AND OF THE INJECTION AND CONFINING ZONE(S) WITHIN 

THE AREA OF 

REVIEW; INCLUDING GEOLOGIC CHANGES BASED ON FIELD DATA WHICH MAY 

INCLUDE 

GEOLOGIC CORES, OUTCROP DATA, SEISMIC SURVEYS, WELL LOGS, CAPILLARY 

PRESSURE 

TESTS AND NAMES and lithologic descriptions; 

Basis for CCS Group Comments: Capillary pressure is too hard to measure outside 

the lab; how comparable are lab results to what goes into the ground. Sidewall 

core may not be sufficient to do this, and it is difficult to core the whole of 

the confining and injection zones. Rewording keeps the usefulness of capillary 

pressure in the provision without making it a mandatory use. 

Individual Response: EPA acknowledges that laboratory methods are standard for determining 

capillary pressures regardless of formation permeability and that in situ measurements would 

require drilling of a well. However, EPA also anticipates that test wells will be drilled to support 

geologic site characterization of the proposed GS sites and can be used to collect subsurface 

samples (for laboratory determination of capillary pressure) and take other necessary 

measurements. 

EPA recognizes that this information may not be available until after a well has been drilled. 

EPA revised §146.82 so that the final regulation specifies separate requirements for information 

to be submitted with the permit application and before well construction is approved (at 

§146.82(a)) and information to be submitted before operation of the well is authorized (at 

§146.82(c)). Final information on injection zone pressures would be required following drilling 

of the well, at §146.82(c)(4). 

EPA believes that information on capillary entry pressure is necessary and appropriate. Capillary 

entry pressure measurements on core samples can quantify the amount of buoyant force the 

confining zone can maintain before failure (World Resources Institute, 2008). 

Letter ID: 0190 Comment ID: 24418 Letter Lines: 2051 to 2062 

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

Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provision: 146.82(d)(5) 

Proposed CCS Group Recommendations: (5) KNOWN geomechanical information on 

92
fractures, stress, ductility, rock strength, and in situ fluid pressures within 

the confining zone(s) WITHIN THE AREA OF REVIEW; and 

Basis for CCS Group Comments: Clarification. 

Rule Provision: 146.82(d)(6) 

Proposed CCS Group Recommendations: Delete item 6 because this issue is covered 

under other sections such as (b). 

Individual Response: EPA acknowledges the comment but did not make the suggested edits. 

The Agency believes that the site characterization requirements at §146.82, including 

geomechanical information and geologic and topographic maps and cross sections, are essential 

to proper siting of a GS well and are the foundation for a detailed understanding of the local and 

regional geology, and that the owner or operator should collect this information, regardless of 

whether it is known in advance of the siting process. Collecting and evaluating this data supports 

important evaluations regarding the suitability of the site to receive and contain injected CO2. 

EPA recognizes that this information may not be available until after a well has been drilled. 

EPA revised §146.82 so that the final regulation specifies separate requirements for information 

to be submitted with the permit application and before well construction is approved (at 

§146.82(a)) and information to be submitted before operation of the well is authorized (at 

§146.82(c)). Final information on injection zone pressures would be required following drilling 

of the well, at §146.82(c)(4). 

Letter ID: 0190 Comment ID: 24419 Letter Lines: 2064 to 2101 

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

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

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provision: 146.82(e) 

Proposed CCS Group Recommendations: (e) A tabulation RECORD of all wells 

ARTIFICIAL PENETRATIONS within the area of review which penetrate THAT REACH 

the injection or confining zone(s). Such data AS AVAILABLE IN THE PUBLIC RECORD 

must include a description of each well’s PENETRATION’S type, construction, 

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

additional information the Director may require; 

Basis for CCS Group Comments: "Artificial penetrations" is a more inclusive 

term. 

Rule Provision: 146.82(f) 

93
Proposed CCS Group Recommendations: (f) Maps and stratigraphic cross sections 

indicating the general vertical and lateral limits of all USDWs, water wells and 

springs within the area of review, their positions relative to the injection 

zone(s) and the direction of water movement, where known; POTENTIOMETRIC 

(WATER LEVEL) SURFACE MAP(S) OF EXISTING AQUIFERS BEING UTILIZED AS 

PRIVATE OR 

PUBLIC WATER SUPPLIES AND THE DIRECTION OF GROUNDWATER FLOW IN 

THESE AQUIFERS 

WITHIN THE AREA OF REVIEW. AT LEAST TWO GEOLOGIC CROSS SECTIONS 

SHOWING THE 

THICKNESS AND GENERAL VERTICAL AND LATERAL LIMITS OF ALL USDWS 

WITHIN THE AREA 

OF REVIEW. 

Basis for CCS Group Comments: This revision more accurately identifies the 

information that is needed and should be considered for permitting. 

Rule Provision: 146.82(g) 

Proposed CCS Group Recommendations: (g) Baseline geochemical data on 

subsurface formations, including all USDWs in the area of review COMPILATION 

OF AVAILABLE GEOCHEMICAL DATA ON THE PROPOSED INJECTION ZONE AND 

NEAREST POROUS 

AND PERMEABLE FORMATION ABOVE THE CONFINING ZONE. 

Basis for CCS Group Comments: Limits the data to be submitted to available 

information and to the injection zone and the zone immediately above the 

confining zone which are the zones most likely to be monitored for potential CO2 

leakage. 

Individual Response: EPA believes that a determination of what information may be necessary 

for a specific Class VI well and what information is available in the public record will be sitespecific and based on data availability and data quality. For instance, in meeting the requirement 

to tabulate information on wells in the AoR, the Director has the discretion to require the owner 

or operator to supplement a data records search if there is reason to believe that the 

incompleteness of available information could compromise USDW protection from 

endangerment. Please see the final rule and the discussion of permitting and geologic site 

characterization in the preamble for additional information. 

EPA believes that a thorough understanding of the hydrogeologic conditions of all USDWs in 

the AoR is necessary, and disagrees with the suggested edits because the GS rule, as written, 

affords flexibility to owners or operators and Directors to tailor the site characterization process 

to the unique features of the site. EPA encourages owners or operators and Directors to 

collaborate and consult during site characterization to discuss information needs and ensure that 

all appropriate data to assess the suitability of the site are collected. The Director also has the 

94
authority to request additional hydrogeologic data or other data on USDWs. 

The Agency believes that the requirement at §146.82(a)(6) to submit baseline geochemical data 

on subsurface geologic formations, including all USDWs in the AoR, is appropriate and 

protective of USDWs. EPA believes that this data will support monitoring plan development, 

inform injectate fate and transport model development (e.g., by providing appropriate input 

parameters), and provide information needed to respond to any unexpected and unpermitted 

leaks outside of the injection zone. The baseline geochemical information will allow the owner 

or operator and permitting authority to evaluate monitoring data and identify any changes in 

subsurface geochemistry that may indicate fluid movement. 

The rule requires geochemical analysis of, at a minimum, the injection zone, confining zone, and 

all USDWs (§146.82(a)(6)). These geochemical tests are necessary to ensure the adequacy of the 

confining system and to serve as a baseline for future monitoring. The Director has the discretion 

to require geochemical analysis of additional subsurface zones if, in the Director's opinion, they 

are necessary for the protection of USDWs from endangerment. 

Letter ID: 0190 Comment ID: 24420 Letter Lines: 2103 to 2149 

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 Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provision: 146.82(h) 

Proposed CCS Group Recommendations: (h) Proposed operating data: 

(1) Average and maximum daily INJECTION rate and volume of the carbon dioxide 

stream; 

(2) Average and maximum SURFACE injection pressure; 

Clarifications 

Basis for CCS Group Comments: Technical clarifications. 

Rule Provision: 146.82(i) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Rule Provision: 146.82(j) 

Proposed CCS Group Recommendations: Support the proposed language. 

95
Basis for CCS Group Comments: Agree with EPA’s rationale. 

Rule Provision: 146.82(k) 

Proposed CCS Group Recommendations: (k) Proposed stimulation program and a 

determination that stimulation will not compromise containment; 

Basis for CCS Group Comments: "Interfere" is too ambiguous and should be 

replaced by "compromise" which limits concerns to situations where containment 

may be lost. 

Rule Provision: 146.82(n) 

Proposed CCS Group Recommendations: (n) A WELLBORE schematic or other 

appropriate drawings of the surface and of the subsurface construction details 

of the well AND SURFACE WELLHEAD CONSTRUCTION. 

Basis for CCS Group Comments: (n) Technical clarification. 

Rule Provision: 146.82(q) 

Proposed CCS Group Recommendations: (q) The ANY status of corrective action 

on wells in the area of review; 

Basis for CCS Group Comments: Clarifies that wells not needing corrective action 

will not have a corrective action status. 

Individual Response: EPA acknowledges the commenter’s support for portions of the subject 

requirements. EPA disagrees that the suggested technical clarifications are necessary. EPA adds 

that it is developing guidance for owners or operators on the geologic site characterization and 

AoR and corrective action processes. These guidances will provide recommendations and clarify 

the intent of all required elements of a permit application. The guidances can be found on EPA’s 

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

Letter ID: 0190 Comment ID: 24421 Letter Lines: 2151 to 2155 

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

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

Comment: Rule Provision: 146.83(a) & (a)(1) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. 

96
Letter ID: 0190 Comment ID: 24422 Letter Lines: 2157 to 2169 

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

Comment Code: 3110 2.1.1 Proposed siting requirements (i.e., injection/confining zones, 

trapping mechanism) 

Comment: Rule Provision: 146.83(a)(2) 

Proposed CCS Group Recommendations: (2) A confining zone(s) that is LATERALLY 

CONTINUOUS AND free of KNOWN TRANSECTING, transmissible faults or fractures and 

of sufficient areal extent and integrity to contain the injected carbon dioxide 

stream and displaced formation fluids and allow injection at proposed maximum 

pressures and volumes without initiating or propagating fractures in the 

confining zone(s); and OVER AN AREA SUFFICIENT TO PREVENT THE MOVEMENT OF 

INJECTED OR DISPLACED FLUIDS INTO A USDW; 

Basis for CCS Group Comments: The proposed clarification keeps the emphasis on 

the non-endangerment of USDWs and limits the requirements to that which is known 

or can be readily determined. 

Individual Response: The Agency believes that the requirement at §146.83(a)(2) that the 

confining zone be free of transmissive faults or fractures is appropriate for Class VI wells and is 

necessary to ensure containment of the injectate and that requiring the confining zone to be free 

of transmissive faults maximizes protection of USDWs from endangerment. EPA believes that 

the text regarding propagation of faults and fractures is important to avoid the potential for fluid 

movement and to ensure that injection is at appropriate pressures. Class I hazardous waste 

injection well operators must also meet a similar requirement that the site is free of transmissive 

faults or fractures; they have successfully made such demonstrations in the past. While core 

samples obtained through drilling and hydraulic testing are direct methods to obtain such 

information, geophysical techniques such as seismic or electromagnetic surveys can also be used 

in many geologic settings to demonstrate the absence of or identify and characterize the presence 

of faults or fractures. EPA adds that the Director will evaluate all geologic data on the site to 

ensure protection of USDWs from endangerment before approving a site for a GS project. 

Letter ID: 0190 Comment ID: 24423 Letter Lines: 2171 to 2183 

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

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

(seeking comment) 

Comment: Rule Provision: 146.83(b) 

Proposed CCS Group Recommendations: (b) At the Director’s discretion, owners 

or operators of Class VI wells must identify and characterize additional zones 

that will impede vertical fluid movement, are free of faults and fractures that 

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may interfere with containment, allow for pressure dissipation, and provide 

additional opportunities for monitoring, mitigation and remediation. 

Basis for CCS Group Comments: This paragraph creates a presumption that 

additional confining zones WILL be required. It is also redundant given the 

previous sections. Providing for a confining zone that meets the requirements 

should be sufficient. Any further identification of confining zones would 

potentially eliminate zones useful for future geologic sequestration. 

Individual Response: EPA clarifies that secondary confining zones are not required for all GS 

sites. Rather, secondary confining zones are required when the Director determines that these 

zones are needed to maximize the protection of USDWs from endangerment. EPA retains the 

requirement to identify additional containment/confining zones, if required by the Director, as 

proposed (e.g., §146.83(b)). EPA believes that, in some situations, the presence of additional 

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

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

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

remediation. The Agency's decision is supported by commenters representing states, water 

associations, and an electric utility who assert that these requirements promote a flexible, riskbased, 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: 0190 Comment ID: 24424 Letter Lines: 2185 to 2196 

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

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

Comment: Rule Provision: 146.84(a) 

Proposed CCS Group Recommendations: (a) The area of review is the region 

surrounding the geologic sequestration project that may be impacted by the 

injection activity. The area of review is based on computational modeling that 

accounts for the physical and chemical properties of all phases of the injected 

carbon dioxide stream. THE SUBSURFACE THREE-DIMENSIONAL EXTENT OF THE 

CARBON 

DIOXIDE PLUME, ASSOCIATED PRESSURE FRONT, AS WELL AS THE OVERLYING 

FORMATIONS 

AND SURFACE AREA ABOVE THAT DELINEATED REGION. 

Basis for CCS Group Comments: Edits make this provision consistent with the 

definition of "Area of Review", which was revised. 

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

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

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

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

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

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

subsurface storage site and the AoR. Although EPA disagrees with the commenter's suggested 

change, the Agency has carefully considered all comments on the AoR definition at 146.84(a) 

and modified it to read as follows: The region surrounding the geologic sequestration project 

where USDWs may be endangered by the injection activity. The area of review is delineated 

using computational modeling that accounts for the physical and chemical properties of all 

phases of the injected CO2 stream and is based on available site characterization, monitoring, 

and operational data. EPA believes that this definition is sufficiently broad and describes both 

the intent of the computational modeling and the relationship of the AoR to areas that are subject 

to the risks associated with injection. 

Letter ID: 0190 Comment ID: 24425 Letter Lines: 2198 to 2209 

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

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action 

plan 

Comment: Rule Provision: 146.84(b) 

Proposed CCS Group Recommendations: (b) The owner or operator of a Class VI well 

must prepare, maintain, and comply with a plan to delineate the area of review 

for a proposed geologic sequestration project, periodically reevaluate the 

delineation, and perform corrective action that meets the requirements of this 

section and is IN A MANNER AND AT A FREQUENCY acceptable to the Director. As a 

part of the permit application, for approval by the Director the owner or 

operator must submit an area of review and corrective action plan that includes 

the following information: 

Basis for CCS Group Comments: Clarification. 

Individual Response: EPA disagrees with the suggested change, and is retaining the approach 

of setting a minimum fixed frequency for reevaluating the AoR but has, based on commenters' 

input, changed the frequency from ten years to at least every five years, as specified in 

§146.84(e). EPA agrees with commenters that site-specific information is an important factor in 

determining an appropriate AoR reevaluation frequency, and adds that the owner or operator's 

AoR and corrective action plan must describe the minimum fixed frequency for reevaluating the 

AoR and the site-specific conditions on which this frequency is based. EPA adds that the 

Director will evaluate the proposed plan in connection with a review of a vast amount of 

geologic and proposed operating data in determining whether to approve the plan. EPA is 

developing guidance describing recommended approaches to preparing all of the required GS 

project plans, which will address considerations for determining an appropriate AoR reevaluation 

schedule. The guidance will be available on EPA's web site, at 

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

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Letter ID: 0190 Comment ID: 24426 Letter Lines: 2211 to 2221 

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

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

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action 

plan 

Comment: Rule Provision: 146.84(b)(2)(i) & (ii) 

Proposed CCS Group Recommendations: (i) The minimum fixed frequency, not to 

exceed 10 years, the owner or operator proposes to reevaluate the area of 

review; (ii) The monitoring and operational conditions that would warrant a 

reevaluation of the area of review prior to the next scheduled reevaluation as 

determined by the minimum fixed frequency established in paragraph (b)(2)(i) of 

this section. 

Basis for CCS Group Comments: These provisions in (i) and (ii) are rendered 

unnecessary by the revisions to section 146.84(b). 

Individual Response: EPA believes that periodic AoR reevaluation at a set frequency of at least 

every five years is necessary to ensure protection of USDWs from endangerment and address the 

uncertainties inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure 

that a deliberate effort is made to verify, based on monitoring and operational data, that the CO2 

plume is moving within the subsurface as predicted. EPA believes that less frequent 

reevaluations may not be sufficient to appropriately model plume and pressure front movement, 

establish conditions for corrective action, and ensure protection of USDWs from endangerment. 

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

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

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

Letter ID: 0190 Comment ID: 24427 Letter Lines: 2223 to 2229 

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

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

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action 

plan 

Comment: Rule Provision: 146.84(b)(2)(iii) 

Proposed CCS Group Recommendations: iii (I) How monitoring and operational 

data (e.g., injection rate and pressure) will be used to inform an area of 

review reevaluation; and 

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Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment and the final rule retains this provision. 

Letter ID: 0190 Comment ID: 24428 Letter Lines: 2231 to 2242 

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

Comment Code: 3400 2.2.2 Corrective Action 

Comment: Rule Provision: 146.84(b)(2)(iv) 

Proposed CCS Group Recommendations: iv (II) How corrective action will be 

conducted to meet the requirements of paragraph (d) of this section, including 

what corrective action will be performed prior to injection and what, if any, 

portions of the area of review will have corrective action addressed on a phased 

basis and how the phasing will be determined; how corrective action will be 

adjusted if there are changes in the area of review; and how site access will be 

guaranteed ARRANGED for future corrective action. 

Basis for CCS Group Comments: Future access cannot be guaranteed for an area in 

advance that may not even be within the boundaries of the AOR/ project. 

Individual Response: EPA is retaining this requirement as proposed. The purpose of the 

corrective action requirement at §146.84(d) is to ensure that all wells in the AoR that have the 

potential to cause the movement of CO2 or other fluids into or between USDWs receive 

appropriate corrective action. In general, to meet this requirement, the owner or operator will 

most likely need to obtain the right of access to wells that may require corrective action, and 

demonstrate they have done this in their proposed AoR and corrective action plan. In the AoR 

and corrective action plan, the owner or operator must describe how site access will be 

guaranteed for future corrective action as specified in §146.84(b)(2)(iv). 

Letter ID: 0190 Comment ID: 24429 Letter Lines: 2244 to 2254 

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

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

Comment: Rule Provision: 146.84(c)(1) 

Proposed CCS Group Recommendations: (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 INJECTION INDUCED 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 FOR a fixed time period as determined by the 

Director. The model MODELING must: 

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Basis for CCS Group Comments: Clarification 

Individual Response: Based on an evaluation of all comments received, EPA has clarified this 

language in the final rule at 146.84(c)(1). 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.” 

Letter ID: 0190 Comment ID: 24430 Letter Lines: 2256 to 2268 

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

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

Comment: Rule Provision: 146.84(c)(1)(i) & (ii) 

Proposed CCS Group Recommendations: (i) Be based on detailed geologic data 

collected AVAILABLE to characterize the injection zone, confining zone and 

any additional zones; and anticipated operating data, including injection 

pressures, rates and total volumes over the proposed life of the geological 

sequestration project THE DURATION OF INJECTION; 

(ii) Take into account any RELEVANT geologic heterogeneities, AND data 

quality, and their possible impact on model predictions; and 

Basis for CCS Group Comments: Allows the use of all available data, not just 

data collected specifically for this permit. 

Individual Response: EPA agrees that detailed geologic data is invaluable to modeling an 

accurate AoR. EPA clarifies that owners or operators may use existing data as well as data 

collected during site characterization to predict the AoR. The final rule retains the language in 

§146.84(c)(1)(i) as proposed, and modifies §146.84(c)(1)(ii) slightly to require owners or 

operators to take into account “other discontinuities” in addition to geologic heterogeneities 

when predicting the AoR. 

EPA disagrees that only the injection and confining zones should be included in AoR modeling 

of GS sites. EPA believes that the modeling should also take into account the possibility of 

displaced fluids or brines caused by a lateral and/or vertical pressure plume, and therefore it may 

be necessary to include additional zones along with the confining/injection zones to ensure the 

integrity of the confining zone and ultimately protect a USDW from endangerment. 

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Letter ID: 0190 Comment ID: 24431 Letter Lines: 2270 to 2274 

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

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

Comment: Rule Provision: 146.84(c)(1)(iii) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the commenter’s support; the final GS rule retains the 

provision in §146.84(c)(1)(iii) as proposed. 

Letter ID: 0190 Comment ID: 24432 Letter Lines: 2276 to 2286 

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

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

available information, depth of wells) 

Comment: Rule Provision: 146.84(c)(2) 

Proposed CCS Group Recommendations: (2) Using methods approved by the 

Director, Identify all KNOWN ARTIFICIAL penetrations INTO THE CONFINING ZONE 

AVAILABLE IN THE PUBLIC RECORD, including active and abandoned wells and 

underground mines, in the area of review that may penetrate REACH 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 

Basis for CCS Group Comments: Changed for consistency with earlier language. 

Individual Response: EPA is retaining the requirement as proposed. EPA agrees with 

commenters that, for most GS sites, relying on database and other public records searches (i.e., 

of "known" artificial penetrations) will be sufficient to meet the requirements at §146.84(c)(2). 

However, the Agency recognizes that there may be situations where additional surveys or 

research to locate 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, based on knowledge of the site or of available data, that the incompleteness of 

information on known wells could compromise USDW protection. 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 is not publically available) to ensure that all 

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necessary corrective action is performed. 

Letter ID: 0190 Comment ID: 24433 Letter Lines: 2288 to 2295 

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

Comment Code: 3400 2.2.2 Corrective Action 

Comment: Rule Provision: 146.84(c)(3) 

Proposed CCS Group Recommendations: (3) Determine which abandoned wells 

IDENTIFIED PURSUANT TO 146.84 (C) (2) in the area of review have been 

plugged (as required by §146.92) in a manner that prevents the movement of 

carbon dioxide or associated FORMATION fluids that may endanger USDWs. 

Basis for CCS Group Comments: Remove "in the area of review" as redundant. 

Individual Response: EPA clarifies that the term "associated fluids," as proposed in 

§146.84(c)(3), refers to formation fluids, other injectates, etc., that may be present in the 

subsurface and affect movement of the CO2 plume and/or pressure front. EPA believes this 

terminology would incorporate any fluids in the subsurface that could potentially move through 

artificial penetrations and affect USDWs. EPA has revised the language at §146.84(c)(3) to read, 

"... carbon dioxide or other fluids that may endanger USDWs..." EPA disagrees that deleting the 

term area of review is necessary and has retained the term in the final rule language. 

Letter ID: 0190 Comment ID: 24434 Letter Lines: 2297 to 2308 

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

Comment Code: 3460 2.2.2.3 Acceptable corrective action techniques for GS sites (e.g., 

cements) 

Comment: Rule Provision: 146.84(d) 

Proposed CCS Group Recommendations: Owners or operators of Class VI wells must 

perform corrective action USING MATERIALS SUITABLE FOR USE WITH THE CARBON 

DIOXIDE STREAM AND FORMATION FLUIDS, on all wells in the area of review 

IDENTIFIED IN 146.84(C)(2) that are determined to need corrective action". 

using methods necessary to prevent the movement of fluid into or between USDWs 

including use of corrosion resistant materials, where appropriate. 

Basis for CCS Group Comments: Experience with CO2 based EOR strongly supports 

the use of many conventional materials that might not meet the technical 

definition of "corrosion resistant". 

Individual Response: EPA revised the text at §146.84(d) to require the use of materials that are 

104
"compatible with the carbon dioxide stream." EPA believes this language change addresses 

commenters' concerns and is also consistent with other language regarding materials 

requirements in the GS rule. 

Letter ID: 0190 Comment ID: 24435 Letter Lines: 2310 to 2318 

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

Comment Code: 3400 2.2.2 Corrective Action 

Comment: Rule Provision: 146.84(e) 

Proposed CCS Group Recommendations: (e) If monitoring data indicate an 

endangerment to USDWs, the owner or operator must notify the Director and cease 

operations as required by § 146.94. 

Basis for CCS Group Comments: This is not needed since §146.94 already specifies 

the notification and cessation of injection. We suggest deletion of this 

language as unnecessarily duplicative. 

Individual Response: Based on consideration of all public comments and other information, 

EPA deleted this provision from §146.84. The final rule now contains a provision in §146.91(c) 

that requires the owner or operator to report within 24 hours any evidence that the carbon dioxide 

stream or associated pressure front may cause an endangerment to a USDW. EPA believes this 

change consolidates reporting requirements in one place and provides additional clarity. 

Letter ID: 0190 Comment ID: 24436 Letter Lines: 2320 to 2329 

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

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

Comment: Rule Provision: 146.84(f) 

Proposed CCS Group Recommendations: (f) At the minimum fixed frequency, not to 

exceed 10 years, as specified in the approved area of review and corrective 

action plan, or When monitoring and operational conditions warrant, owners or 

operators must: 

Basis for CCS Group Comments: Rather than a fixed time period, we recommend 

following a performance based approach that would be based on significant 

changes in injection parameters or anomalous monitoring results. 

Individual Response: EPA agrees that site-specific factors should be considered in the 

reevaluation schedule, and notes that the AoR and corrective action plan must specify the sitespecific monitoring and operational conditions that warrant reevaluation, as specified in 

§146.84(b)(2)(ii). In addition, the Director has discretion to require more frequent AoR 

105
reevaluation if he or she has reason to believe, based on site-specific information, that a five-year 

reevaluation schedule is not sufficiently protective of USDWs. However, EPA believes that 

setting a minimum reevaluation frequency is appropriate. In the final rule, the Agency changed 

the minimum frequency for the AoR reevaluation at §146.84(e) from ten years to at least every 

five years in the final GS rule. EPA believes that this revised frequency addresses commenters' 

concerns 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. 

Letter ID: 0190 Comment ID: 24437 Letter Lines: 2331 to 2338 

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

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action 

plan 

Comment: Rule Provision: 146.84(f)(4) 

Proposed CCS Group Recommendations: (4) Submit an amended area of review and 

corrective action plan or demonstrate to the Director through monitoring data 

and modeling results that no amendment CHANGE to the area of review and 

corrective action plan is needed. 

Basis for CCS Group Comments: Clarification 

Individual Response: EPA disagrees with the suggested change and believes the proposed text 

is clear as written. For additional information on EPA's approach to AoR and corrective action, 

please see the final rule and preamble. 

Letter ID: 0190 Comment ID: 24438 Letter Lines: 2340 to 2349 

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

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

Comment: Rule Provision: 146.84(g) 

Proposed CCS Group Recommendations: (g) The emergency and remedial response plan 

(as required by § 146.94) and a demonstration of financial responsibility (as 

described by § 146.85) must account for the entire area of review AS MODIFIED 

PURSUANT TO § 146.94(F), regardless of whether or not corrective action in the 

area of review is phased. 

Basis for CCS Group Comments: Need to add phrase to account for the periodic 

reevaluations and possible revisions that will be occurring. 

Individual Response: EPA agrees with the commenter and has modified the final rule at 

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§146.84(f) to require the emergency and remedial response plan and the demonstration of 

financial responsibility to take into account the most recently evaluated AoR. 

Letter ID: 0190 Comment ID: 24439 Letter Lines: 2351 to 2366 

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

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

CFR 146.85) 

Comment: Rule Provision: 146.85(a) 

Proposed CCS Group Recommendations: (a) The owner or operator must demonstrate 

and maintain financial responsibility and resources for corrective action (that 

meets the requirements of § 146.84), injection well plugging (that meets the 

requirements of § 146.92), post-injection site care and site closure (that meets 

the requirements of § 146.93), and emergency and remedial response (that meets 

the requirements of § 146.94) in a manner prescribed by the Director until: 

(1) The Director receives WELL PLUGGING REPORT IDENTIFIED IN 146.92(D) and 

approves OR COMPLETION OF the completed post-injection site care and site 

closure plan AS APPROPRIATE; and 

Basis for CCS Group Comments: Maintenance of the well plugging financial 

obligation until site closure is not necessary. The Director should have the 

authority to release the obligation once the well is plugged. 

Individual Response: EPA will allow owners or operators to use separate financial 

responsibility instruments for different GS activities. However, owners or operators must 

demonstrate adequate financial responsibility for all required activities, including well plugging, 

with their permit application, per §146.82(a)(14). In addition, on an annual basis, the owner or 

operator must adjust the cost estimate for inflation, increase or decrease the value of the financial 

instrument to match the cost estimate, and provide any updated information related to their 

financial responsibility instrument(s), or at any other time deemed appropriate by the Director. 

These annual reviews provide a mechanism for revising cost estimates up or down to account for 

changes in the project, including the execution of environmental obligations as phases of a GS 

project are completed. 

Regarding the suggested edit at §146.85(a)(1), EPA clarifies that the owner or operator may call 

upon their financial instrument when the phase of the project for which the instrument was 

required is complete and all financial obligations for that instrument have been met, as specified 

in §146.85(b)(2). For example, when the injection well is plugged to the Director's satisfaction, 

the owner or operator's financial instrument will be released if it was not used. 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. The guidance will include a 

discussion on how best to estimate costs to assist Class VI well owners or operators, third party 

107
insurers or providers of financial instruments, and permitting authorities in developing estimates 

of the costs associated with various GS activities. The guidance is available on EPA's website at 

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

Letter ID: 0190 Comment ID: 24440 Letter Lines: 2368 to 2378 

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

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

CFR 146.85) 

Comment: Rule Provision: 146.85(b) 

Proposed CCS Group Recommendations: (b) The owner or operator must provide to 

the Director, at a frequency determined by the Director, BUT NO MORE FREQUENTLY 

THAN ANNUALLY, written updates of adjustments to the cost estimate to account 

for any amendments CHANGE to the area of review and corrective action plan 

(§146.84), the injection well plugging plan (§146.92), and the post-injection 

site care and site closure plan (§146.93). 

Basis for CCS Group Comments: Requiring updates more frequently than annually is 

not justified and less frequent updates should be appropriate in many cases. 

Individual Response: Cost estimates will need to be reevaluated after amendments to the area of 

review and corrective action plan, prior to well plugging or site closure, after amendments to the 

emergency and remedial response plan, or at any other time deemed appropriate by the Director. 

The rule will also require annual adjustments to the cost estimates for inflation, as specified in 

§146.85(c)(2). These annual reviews provide a mechanism for revising cost estimates up or 

down to account for changes in the project, including the execution of environmental obligations 

as phases of a GS project are completed. 

EPA did not make the proposed edits at §146.85(b), but did extensively revise and clarify the 

financial responsibility requirements. See the final GS rule and preamble for additional 

information on EPA's final approach. 

Letter ID: 0190 Comment ID: 24441 Letter Lines: 2380 to 2387 

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

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

CFR 146.85) 

Comment: Rule Provision: 146.85(c) 

Proposed CCS Group Recommendations: (c) The owner or operator must notify the 

Director of adverse financial conditions such as bankruptcy, that may affect 

the ability to carry out injection well plugging and post-injection site care 

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and site closure. 

Basis for CCS Group Comments: Clarification. 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

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

see the final rule and the discussion of financial responsibility in the preamble for additional 

information. 

Letter ID: 0190 Comment ID: 24442 Letter Lines: 2389 to 2397 

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

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

comment) 

Comment: Rule Provision: 146.85(d) 

Proposed CCS Group Recommendations: (d) The operator must provide an adjustment 

of the cost estimate to the Director if the Director has reason to believe that 

original THE MOST RECENT demonstration is no longer adequate to cover the 

cost of injection well plugging (as required by §146.92) and post-injection site 

care and site closure (as required by §146.93) 

Basis for CCS Group Comments: Clarification. 

Individual Response: EPA agrees that it is important to periodically update cost estimates that 

support financial responsibility determinations. EPA clarifies that the GS rule, at §146.85(e), 

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, and the 

PISC and site closure plan. 

Letter ID: 0190 Comment ID: 24443 Letter Lines: 2399 to 2408 

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

Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 

146.86) 

Comment: Rule Provision: 146.86(a)(1) 

Proposed CCS Group Recommendations: (1) Prevent the movement of fluid into or 

between USDWs or into any unauthorized zones; CONTAINING ANY CONTAMINANT 

INTO 

USDWS, IF THE PRESENCE OF THAT CONTAMINANT MAY CAUSE A VIOLATION OF 

ANY PRIMARY 

DRINKING WATER REGULATION UNDER 40 CFR PART 142 OR MAY OTHERWISE 

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ADVERSELY 

AFFECT THE HEALTH OF PERSONS; 

Basis for CCS Group Comments: The proposed changes follow the non-endangerment 

standard that is the basis of the UIC program. 

Individual Response: EPA disagrees that §146.86 as written does not meet the nonendangerment standard as required under the SDWA. EPA believes that protection of USDWs 

from endangerment and prevention of fluid movement between formations is paramount and 

believes that the language as proposed meets the non-endangerment standard. Appropriately 

designed and constructed wells are necessary to prevent endangerment to USDWs and maintain 

integrity of the well throughout the lifetime of a GS project. This is the foundation of the 

requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 

146.87. 

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

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

and preamble for additional information. 

Letter ID: 0190 Comment ID: 24444 Letter Lines: 2410 to 2426 

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

Comment Code: 3860 2.3.3 Well component degradation 

Comment: Rule Provision: 146.86(b)(1) 

Proposed CCS Group Recommendations: (1) Casing and cement or other materials 

used in the construction of each Class VI well must have sufficient structural 

strength and be designed for the operating life of the geologic sequestration 

project WELL. All well materials must be compatible SUITABLE FOR USE with 

the fluids with which the materials may be expected to come into contact and 

meet or exceed TEST standards OR PRACTICES developed for such materials by the 

American Petroleum Institute, ASTM International, or comparable standards 

acceptable to the Director. The casing and cementing program must be designed to 

prevent the movement of fluids into or between USDWs. In order to allow the 

Director to determine and specify casing and cementing requirements, the owner 

or operator must provide the following information: 

Basis for CCS Group Comments: The life of a geologic sequestration project could 

be different than the life of the well. Class VI well design should be based on 

the life of the well. 

Individual Response: EPA disagrees that the casing, cement, or other materials should only be 

designed for the period of the injection process, rather than the life of the sequestration project. 

GS projects are anticipated to have long life spans in comparison to other types of deep injection 

wells. Not only must Class VI wells be able to function safely and properly over the lifespan of 

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the GS project, but they must be constructed such that USDWs remain protected after well 

plugging. The requirements at §146.86 will ensure that the well can maintain integrity 

throughout the proposed life span of the project, including after the injection well is plugged and 

through the post-injection site care period and beyond. While the risk profile of a GS site will 

decrease following cessation of injection, EPA believes that Class VI wells must be designed to 

protect USDWs from endangerment for the life of the project. Furthermore, rigorous casing and 

cementing help ensure that the Class VI well will not serve as a conduit for movement of fluids 

associated with future injection operations. 

Letter ID: 0190 Comment ID: 24445 Letter Lines: 2428 to 2435 

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

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment) 

Comment: Rule Provision: 146.86(b)(1)(v) 

Proposed CCS Group Recommendations: (v) Corrosiveness COMPOSITION of the 

carbon dioxide stream and formation fluids; 

Basis for CCS Group Comments: There is no method for measurement of 

"corrosiveness" of a CO2 stream. The relevant information is the composition of 

the CO2 stream. 

Individual Response: EPA clarifies that, although corrosiveness does not have a unit of 

measure, corrosiveness can be technically measured and described. Procedures that can identify 

corrosion (or the absence of corrosion) in a Class VI well provide valuable operational 

information that the Director needs to determine appropriate standards for the tubing and packer. 

Letter ID: 0190 Comment ID: 24446 Letter Lines: 2437 to 2441 

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

Comment Code: 3860 2.3.3 Well component degradation 

Comment: Rule Provision: 146.86(b)(1)(vi) 

Proposed CCS Group Recommendations: (vi) Down-hole temperatures AND PRESSURES; 

Basis for CCS Group Comments: Technical clarification 

Individual Response: EPA clarifies that information on down-hole pressures is required at 

§146.86(b)(1)(ii). 

Letter ID: 0190 Comment ID: 24447 Letter Lines: 2443 to 2448 

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

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

Comment: Rule Provision: 146.86(b)(1)(viii) 

Proposed CCS Group Recommendations: (viii) Type or grade of cement AND 

ADDITIVES; and 

Basis for CCS Group Comments: Technical revision 

Individual Response: EPA agrees with the suggestion that §146.86(b)(1)(viii) be revised to also 

address cement additives. In the final GS rule, the subparagraph reads as follows: "Type or grade 

of cement and cement additives." 

Letter ID: 0190 Comment ID: 24448 Letter Lines: 2450 to 2463 

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: Rule Provision: 146.86(b)(2) 

Proposed CCS Group Recommendations: (2) Surface casing must extend through the 

base of the lowermost USDW ABOVE THE INJECTION ZONE and be cemented to the 

surface EXCEPT THAT THE DIRECTOR MAY APPROVE A COMBINATION OF 

CEMENTED SURFACE 

CASING AND CEMENTED LONG STRING CASING TO ACHIEVE CONTINUOUS 

CEMENT FROM THE 

SURFACE THROUGH THE BASE OF THE LOWERMOST USDW ABOVE THE 

INJECTION ZONE. 

Basis for CCS Group Comments: Surface casing need not be cemented through the 

base of the lowermost USDW if a combination of cement on the surface casing and 

long-string casing achieves continuous cement through the base of the lowermost 

USDW above the injection zone. In some parts of the US, USDWs are very deep and 

this standard may preclude geologic sequestration at otherwise appropriate sites 

in these areas. 

Individual Response: EPA believes that the regulations allow appropriate flexibility regarding 

the surface casing. The GS final 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 or 

multiple strings of casing and cement. It does not, however, specify how cementing would be 

accomplished, and gives flexibility to the owner or operator to propose alternate methods to 

provide a sufficient amount of cement to meet the standard that USDWs are protected. EPA 

notes that there are many potential ways to meet the requirement, such as the use of staged 

cementing. 

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The Director will evaluate the appropriateness of the owner or operator's proposed well 

construction procedures based on site-specific information about the injection project, including 

injection pressures, injection and confining zone lithology, and information about the carbon 

dioxide stream as provided in §146.86(b)(1). See the discussion of Class VI well construction 

requirements in the preamble to the final GS rule for additional information. Additionally, EPA 

is developing guidance on the construction of Class VI wells. This guidance will be available on 

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

As described above, 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. 

Letter ID: 0190 Comment ID: 24449 Letter Lines: 2465 to 2482 

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

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

Comment: Rule Provision: 146.86(b)(3) 

Proposed CCS Group Recommendations: (3) At least one long string casing, using 

a sufficient number of centralizers SET IN A MANNER SO AS TO CREATE A CEMENT 

BOND THROUGH THE INJECTION AND CONFINING ZONE(S). THE LONG STRING 

CASING must 

extend to the injection zone and must be cemented ISOLATED by circulating 

cement to the surface in one or more stages. PLACING CEMENT AND/OR OTHER 

ISOLATION TECHNOLOGIES AS NECESSARY TO PROVIDE ADEQUATE ISOLATION 

OF THE 

INJECTION ZONE AND PROVIDE FOR PROTECTION OF USDWS. 

Basis for CCS Group Comments: Cementing of the long string casing to surface is 

not necessary to protect USDWs, and may have negative consequences. Cement to 

surface would eliminate the ability to monitor pressures in this annulus and 

would limit flexibility of remedial options. As revised, the proposal would 

allow for application and development of alternative technologies. See API RP90 

for description of risk-based approach for managing situations involving annular 

casing pressure. Industry experience with CO2 EOR under the Class II program 

demonstrates the effectiveness of existing cementing procedures. 

Individual Response: EPA disagrees with the suggested edits. EPA believes that the 

requirements for long-string casing are appropriate and offer appropriate flexibility: 

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

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

cementing would be accomplished, and gives flexibility to the owner or operator to propose 

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

protected from endangerment, subject to the approval of the Director. 

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

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

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

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

EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, 

operation, and remediation of Class VI wells. Cementing of deep wells has been performed 

successfully in the past by owners or operators of Class I hazardous and Class I municipal waste 

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

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

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

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

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

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

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

Letter ID: 0190 Comment ID: 24450 Letter Lines: 2484 to 2492 

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

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

Comment: Rule Provision: 146.86(b)(4) 

Proposed CCS Group Recommendations: (4) Circulation of cement may be 

accomplished by staging. The Director may approve an alternative method of 

cementing in cases where the cement cannot be recirculated to the surface, 

provided the owner or operator can demonstrate by using logs that the cement 

does not allow fluid movement behind the well bore. 

Basis for CCS Group Comments: Same as above 

Individual Response: EPA disagrees that the requirement should be deleted. Section 

146.86(b)(4) of the final rule allows alternate methods of staging the cement, at the Director's 

discretion, provided the owner or operator can demonstrate using logs that the cement does not 

allow fluid movement behind the wellbore. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

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

Letter ID: 0190 Comment ID: 24451 Letter Lines: 2494 to 2508 

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

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Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment) 

Comment: Rule Provision: 146.86(b)(5) 

Proposed CCS Group Recommendations: (5) Cement and cement additives must be 

compatible SUITABLE FOR USE with the carbon dioxide stream and formation 

fluids and of sufficient quality and quantity to maintain integrity over the 

design OPERATING life of the geologic sequestration project WELL. The 

integrity and location of the cement shall be verified using technology capable 

of evaluating cement quality radially and identifying the location of channels 

to ensure that USDWs are not endangered. 

Basis for CCS Group Comments: Experience with CO2 EOR under the Class II program 

demonstrates the effectiveness of existing cementing materials and procedures. 

Standard API cements have been used in numerous CO2 EOR operations with no 

adverse consequences. Refer to the citations within EPA’s proposed rule 73 FR 

43532-43533: Carey et al., (2007), Crow et al., (2008), and Meyer, J.P (2007). 

Individual Response: EPA recognizes that the oil and gas industry has decades of experience 

injecting CO2 for the purpose of enhanced recovery, and that this practice has led to the 

development of many corrosion mitigation measures that would be appropriate for the design of 

Class VI wells. 

EPA believes that the GS rule provides flexibility: it does not specify materials to be used; 

rather, it provides owners or operators with the flexibility to choose, as long as the materials used 

in Class VI wells are compatible with fluids with which they may come into contact and meet or 

exceed standards developed for such materials by API or ASTM International, or comparable 

standards approved by the Director, as provided at §146.86(b)(1). However, EPA clarifies that 

each individual component of the well system must be described by the owner or operator and 

will be evaluated by the Director and must meet the requirements of the GS rule. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

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

Letter ID: 0190 Comment ID: 24452 Letter Lines: 2510 to 2529 

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

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment) 

Comment: Rule Provision: 146.86(c)(2)(ii) 

Proposed CCS Group Recommendations: (ii) Characteristics COMPOSITION of the 

carbon dioxide stream. (chemical content, corrosiveness, temperature, and 

density); 

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Basis for CCS Group Comments: There is no method for measurement of 

"corrosiveness" of a CO2 stream. The relevant information is the composition, 

not characteristics, of the CO2 stream. The composition of the CO2 stream is 

more relevant to the design of a tubing and packer system. 

Rule Provision: 146.86(c)(2)(iii) - (v) 

Proposed CCS Group Recommendations: (iii) MAXIMUM PROPOSED Injection temperature 

and pressure; 

(iv) MAXIMUM PROPOSED Annular pressure; 

(v) MAXIMUM PROPOSED Injection rate (intermittent or continuous) and volume of 

the carbon dioxide stream; 

Basis for CCS Group Comments: Technical corrections. 

Individual Response: As written, the text at §146.86(c)(3)(ii) accounts for all characteristics of 

the CO2 that could affect the performance of the tubing and packer, including the chemical 

content, corrosiveness, temperature, and density. The suggested revision to refer to CO2 

"composition" would be less precise. EPA clarifies that, although corrosiveness does not have a 

unit of measure, corrosiveness can be technically measured and described. Procedures that can 

identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational 

information that the Director needs to determine appropriate standards for the tubing and packer. 

EPA has revised §146.86(c)(3)(iii) and (iv) to reference the maximum proposed injection 

pressure and maximum proposed annular pressure, respectively. EPA has revised 

§146.86(c)(3)(v) to read "proposed injection rate (intermittent or continuous), and volume and/or 

mass of the carbon dioxide stream." EPA believes that reference to the continuous injection rate 

would be duplicative of the maximum rate. EPA believes that considering the maximum 

injection and annular pressure would be more protective. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

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

Letter ID: 0190 Comment ID: 24453 Letter Lines: 2531 to 2558 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(a) 

Proposed CCS Group Recommendations: (a) During the drilling and construction of 

a Class VI injection well, the owner or operator must run appropriate logs, 

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

116
permeability, and lithology of, and the salinity of any formation fluids in, all 

relevant geologic formations to assure EVALUATE conformance with the 

injection well construction requirements under §146.86, and to establish 

accurate baseline data against which future measurements may be compared. The 

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

knowledgeable log analyst that includes an interpretation of the results of such 

logs and tests. At a minimum, such logs and tests must include: THE DIRECTOR 

MAY REQUIRE SUCH LOGS AND TESTS AS MAY BE NEEDED AFTER TAKING INTO 

ACCOUNT THE 

AVAILABILITY OF SIMILAR DATA IN THE AREA OF THE DRILLING SITE, THE 

CONSTRUCTION 

PLAN, AND THE NEED FOR ADDITIONAL INFORMATION THAT MAY ARISE FROM 

TIME TO TIME 

AS THE CONSTRUCTION OF THE WELL PROGRESSES AND THESE MAY INCLUDE 

THE FOLLOWING: 

Basis for CCS Group Comments: Obtaining the geologic information will not assure 

conformance with well construction requirements, just measure or evaluate it. 

In well defined areas, these evaluations are frequently unnecessary. The 

Director should have discretion to select the appropriate requirements necessary 

to obtain sufficient baseline data and information. For example, in an area 

where a number of wells are being drilled, the logging of surface hole yields 

little useful additional information. 

In particular, this change would allow the Director to reduce the requirements 

when multiple wells are installed for a project. 

Individual Response: EPA disagrees that the requirements for logs, surveys, and tests are 

unnecessary. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information 

about the injection and confining zones and ensure that the well is being drilled and cased as 

approved, and has mechanical integrity. This information is needed to demonstrate that the well 

can be operated and tested in a manner that protects USDWs from endangerment. While the tests 

do provide information on some of the same items, each test provides unique pieces of 

information that build on each other and allow for interpretations not possible with a single test. 

EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods 

that provide equivalent or better information, and the Director may accept information on cores 

of the injection and confining zones from nearby wells if the owner or operator can demonstrate 

that such cores are representative of conditions at the well in question and core retrieval is not 

possible, as specified at §146.87(b). EPA believes that logs and tests must be performed on each 

well drilled regardless of existing information about the area to account for the complexity of 

CO2 injection well construction and the buoyancy of CO2. Existing lithologic and geologic 

information may lack the details needed for site-specific well design and the geology needed to 

support protection of USDWs from endangerment. 

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Letter ID: 0190 Comment ID: 24454 Letter Lines: 2560 to 2564 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(a)(1) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment and agrees that logging and testing 

requirements are appropriate and necessary. The final rule retains the requirements for deviation 

checks at §146.87(a)(1). 

Letter ID: 0190 Comment ID: 24455 Letter Lines: 2572 to 2580 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(a)(2)(i) 

Proposed CCS Group Recommendations: (i) Resistivity, spontaneous potential, and 

caliper logs before the casing is installed; and 

Basis for CCS Group Comments: After a few wells are drilled in an area, these 

evaluations are frequently unnecessary and yield little new information. This is 

an example of where modification of requirements based on Director discretion 

may be appropriate. 

Individual Response: As described above, EPA disagrees that the requirements for logs, 

surveys, and tests are excessive or duplicative. All logs, surveys, and tests listed at §146.87(a) 

are necessary to verify information about the injection and confining zones and ensure that the 

well is being drilled and cased as approved, and has mechanical integrity. EPA notes that the 

Director has the discretion at §146.87(a)(5) to approve alternative methods that provide 

equivalent or better information. 

Letter ID: 0190 Comment ID: 24456 Letter Lines: 2582 to 2593 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(a)(2)(ii) 

Proposed CCS Group Recommendations: (ii) A Cement bond and variable 

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density log, and a temperature log evaluation log(s) after the casing is set 

and cemented. 

Basis for CCS Group Comments: Unusual to run these logs in a surface hole due to 

uniformity of shallow geology. This is an example of where Director discretion 

may be appropriate. 

The proposed change provides more flexibility to select the appropriate log to 

demonstrate adequate cement bond. 

Individual Response: EPA clarifies at §146.87(a)(2)(ii) that owners or operators must perform a 

cement bond (i.e., cement evaluation) log after the casing is set and cemented. 

Letter ID: 0190 Comment ID: 24457 Letter Lines: 2595 to 2599 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(a)(3) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. The final rule retains the requirements 

for the logs required at §146.87(a)(3). 

Letter ID: 0190 Comment ID: 24458 Letter Lines: 2601 to 2610 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(a)(3)(i) 

Proposed CCS Group Recommendations: (i) Resistivity, spontaneous potential, 

porosity, caliper, gamma ray, fracture finder logs and any other logs the 

Director requires BASED ON SITE SPECIFIC CONDITIONS AND RISK-BASED FACTORS 

for 

the given geology before the casing is installed; and 

Basis for CCS Group Comments: It is acceptable to specify basic logging 

requirements, however, special logs should not be specified. Any other 

information from the area should be used instead. 

Individual Response: EPA believes that a minimum suite of logs and tests is necessary at all 

119
Class VI wells. All logs, surveys, and tests listed at §146.87(a) are necessary to verify 

information about the injection and confining zones and ensure that the well is being drilled and 

cased as approved and has mechanical integrity. 

EPA notes that owners or operators will describe in their permit applications how they will 

construct and test the well, and will also submit site-specific information about the subsurface 

geology. The Director will evaluate the proposed logging activities along with site-specific 

geologic information to identify geologic data of interest. 

EPA adds that, should alternative methods be shown to provide equivalent or better information 

or if site-specific conditions and risk factors dictate that other logs are necessary, the Director has 

the discretion at §146.87(a)(5) to require further logs and tests if necessary and to approve 

alternative methods that provide equivalent or better information. 

Letter ID: 0190 Comment ID: 24459 Letter Lines: 2612 to 2619 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(a)(3)(ii) 

Proposed CCS Group Recommendations: (ii) A Cement bond and variable 

density log, and a temperature log EVALUATION LOG(S) after the casing is set 

and cemented. 

Basis for CCS Group Comments: The proposed change provides more flexibility to 

select the appropriate log to demonstrate adequate cement bond. 

Individual Response: EPA clarifies at 146.87(a)(3)(ii) that owners or operators must perform a 

cement bond (i.e., cement evaluation) log after the casing is set and cemented. 

Letter ID: 0190 Comment ID: 24460 Letter Lines: 2621 to 2632 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(a)(4) 

Proposed CCS Group Recommendations: (4) A series of tests TEST(S) designed 

to demonstrate the internal and external mechanical integrity of injection 

wells, which may include: 

(i) A pressure test with liquid or gas; 

(ii) A tracer survey DIAGNOSTIC TOOLS such as oxygen-activation logging; 

(iii) A temperature or noise log; AND/OR 

(iv) A casing inspection log. if required by the Director; and 

120
Basis for CCS Group Comments: Technical and grammatical corrections in (4), (4) 

(ii) and (4)(iii). In (iv), "if required by the Director" is unnecessary. 

Individual Response: EPA disagrees that allowing the use of unspecified "diagnostic tools" 

would provide the same amount of information as the requirement to perform a tracer survey. 

The track record for tracer surveys in evaluating mechanical integrity has been proven over time. 

The Agency clarifies that a tracer survey is one of the mechanical integrity tests that may be 

required by the Director or used by the owner or operator. 

EPA agrees with the commenter about the wording of the casing inspection log requirement at 

§146.87(a)(4) and made the suggested change to improve clarity. In the final regulation, 

§146.87(a)(iv) does not include the phrase, “if required by the Director.” 

Letter ID: 0190 Comment ID: 24461 Letter Lines: 2634 to 2641 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(a)(5) 

Proposed CCS Group Recommendations: (5) Any alternative methods that provide 

equivalent or better information and that are required of and/or approved of 

by the Director. 

Basis for CCS Group Comments: We interpret that (5) applies to 146.87(a) and 

support as proposed. For deletion, same comment as above in (iv). 

Individual Response: EPA retained the language in §146.87(a)(5) as proposed, allowing the 

Director discretion to authorize different methods in that provision, rather than moving such 

authority to 146.87(a), as the commenter requested. EPA notes that §146.87(a)(5) affords the 

Director discretion to approve alternative methods that provide equivalent or better information, 

and the Director may accept information on cores of the injection and confining zones from 

nearby wells if the owner or operator can demonstrate that such cores are representative of 

conditions at the well in question and core retrieval is not possible, as specified at §146.87(b). 

Letter ID: 0190 Comment ID: 24462 Letter Lines: 2643 to 2655 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(b) 

Proposed CCS Group Recommendations: (b) The owner or operator must submit to the 

Director A REPORT DESCRIBING whole cores or sidewall cores REPRESENTATIVE of the 

121
injection zone and confining system and formation fluid samples from the 

injection zone(s). The Director may accept DATA FROM cores AND FLUID SAMPLES 

from nearby wells if the owner or operator can demonstrate that core retrieval 

is not possible and that such cores DATA are representative of conditions 

at the well IN THE WELLBORE. The Director may require the owner or 

operator to core other formations in the borehole. 

Basis for CCS Group Comments: The information required should be sufficient to 

properly describe the injection and confining zones. 

Individual Response: EPA clarifies that it is not the Agency's intent that physical cores be 

submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) 

to read as follows: "The owner or operator must take whole cores or sidewall cores of the 

injection zone and confining system and formation fluid samples from the injection zone(s), and 

must submit to the Director a detailed report prepared by a log analyst that includes: well log 

analyses (including well logs), core analyses, and formation fluid sample information...." 

Letter ID: 0190 Comment ID: 24463 Letter Lines: 2657 to 2666 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(c) 

Proposed CCS Group Recommendations: (c) PRIOR TO INJECTION WELL OPERATION,the 

owner or operator must record PROVIDE REPRESENTATIVE INFORMATION ON the 

fluid FORMATION temperature, FORMATION FLUID pH and conductivity, and 

reservoir pressure and the static fluid level of the injection zone(s). 

Basis for CCS Group Comments: Technical corrections. Reservoir pressure and 

static fluid level are redundant parameters. The phrase "representative 

information" prevents the operator from having to do all tests in all wells. 

Individual Response: EPA disagrees that "reservoir pressure" and "static fluid level" are 

redundant parameters. Although the static fluid level is equal to the bottom hole pressure, this 

may not always be identical to the reservoir pressure. Additionally, measuring the static fluid 

level provides additional assurance that the reading is accurate (or, provides the needed 

information in cases where a good reading is not obtained). In addition, a static fluid level 

measurement provides information regarding the proximity to USDWs that need protection 

afforded to them. 

Letter ID: 0190 Comment ID: 24464 Letter Lines: 2668 to 2679 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

122
Comment: Rule Provision: 146.87(d) 

Proposed CCS Group Recommendations: (d) At a minimum, the owner or operator 

must determine or calculate the following information concerning the injection 

and confining zone(s): (1) Fracture pressure; (2) Other physical and chemical 

characteristics of the injection and confining zones; and (3) Physical and 

chemical characteristics of the formation fluids in the injection zone. 

Basis for CCS Group Comments: With the exception of calculating fracture 

pressure, the requirements of this section appear redundant to other 

requirements of prior sections. The fracture pressure requirement has been added 

to section 146.87(e) below. (2) and (3) are too vague. 

Individual Response: EPA believes that the requirement to provide information on the injection 

and confining zones in §146.87(d) is warranted. As described above, the rule provides flexibility 

to account for the variety of geologic conditions that may be encountered at GS sites. 

Letter ID: 0190 Comment ID: 24465 Letter Lines: 2681 to 2700 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(e) 

Proposed CCS Group Recommendations: e (D) Upon completion but Prior to 

INJECTION WELL operation, the owner or operator must 

conduct the following tests to verify hydrogeologic characteristics of the 

injection zone: (1) A pump test; or (2) Injectivity tests. 

ESTIMATE FRACTURE PRESSURES OF THE INJECTION AND CONFINING ZONES 

AND INJECTIVITY 

OF THE INJECTION ZONE. ESTIMATES SHOULD BE BASED ON REPRESENTATIVE 

HYDROGEOLOGIC 

AND GEOMECHANICAL CHARACTERISTICS OF THE INJECTION ZONE. 

Basis for CCS Group Comments: Allows the use of information such as leak off 

tests conducted during the drilling operation. 

The results of a pump test (pumping fluid from the well) have no relevance for 

an injection well. 

Deletion of the injectivity test would allow the use of non-destructive methods 

to calculate fracture pressure. 

123
Individual Response: EPA clarifies that the owner or operator has the option of using the pump 

tests or injectivity tests specified at §146.87(e) depending on which would provide the most 

valuable information based on site-specific conditions. Further, EPA disagrees that pump tests 

are irrelevant to determining injection zone properties. Depending on the characteristics or depth 

of knowledge of the confining and injection zone formations, pump tests may be necessary to 

prove that no hydraulic connection exists between the injection zone and a USDW. 

EPA disagrees that the wording at §146.87(d) would lead the owner or operator to employ 

destructive testing methods for determination of fracture pressure. The wording "determined or 

calculated" allows for calculations to be performed based on non-destructive methods. 

Letter ID: 0190 Comment ID: 24466 Letter Lines: 2702 to 2712 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(f) 

Proposed CCS Group Recommendations: (f) (e) The owner or operator must 

provide the Director with the opportunity to witness all logging and testing by 

this subpart. The owner or operator must submit a schedule of such activities to 

the Director UPON SPUDDING THE WELL and submit any changes to the schedule 48 

HOURS prior to the scheduled test. 

Basis for CCS Group Comments: The changes reflect the realities of rig 

scheduling and are fully consistent with current Class II requirements and 

practices. 

Individual Response: EPA disagrees that the 30-day notification requirement is unreasonable. 

Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the 

permitting authority in each project will provide much needed field data for assurance of USDW 

protection from endangerment and will help update and refine the permitting process. Adequate 

timing of notification will ensure the Director's ability to be involved. 

Letter ID: 0190 Comment ID: 24467 Letter Lines: 2714 to 2754 

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

Comment Code: 4110 2.4.1.1 Injection pressure limitations 

Comment: Rule Provision: 146.88(a) 

Proposed CCS Group Recommendations: (a) Except during stimulation, the owner 

or operator must ensure that injection pressure does not exceed 90 percent of 

the fracture pressure of the injection zone so as to assure that the injection 

does not initiate new fractures or propagate existing fractures in the injection 

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zone. In no case may injection pressure initiate fractures in the confining 

zone(s) or cause the movement of injection or formation fluids that endangers a 

USDW. THE OWNER OR OPERATOR MUST COMPLY WITH A MAXIMUM INJECTION 

PRESSURE 

LIMIT APPROVED BY THE DIRECTOR AND SPECIFIED IN THE PERMIT. IN 

APPROVING A 

MAXIMUM INJECTION PRESSURE LIMIT, THE DIRECTOR SHALL CONSIDER THE 

RESULTS OF 

WELL TESTS AND, WHERE APPROPRIATE, GEOMECHANICAL OR OTHER STUDIES 

THAT ASSESS 

THE RISKS OF TENSILE FAILURE AND SHEAR FAILURE. THE DIRECTOR SHALL 

APPROVE 

LIMITS THAT, WITH A REASONABLE DEGREE OF CERTAINTY, WILL AVOID 

INITIATION OR 

PROPAGATION OF FRACTURES IN THE CONFINING ZONE OR CAUSE OTHERWISE 

NONTRANSMISSIVE FAULTS TRANSECTING THE CONFINING ZONE TO BECOME 

TRANSMISSIVE. IN NO 

CASE MAY INJECTION PRESSURE CAUSE MOVEMENT OF INJECTION OR 

FORMATION FLUIDS IN A 

MANNER PROHIBITED BY 40 CFR PART 144.12(A). 

Basis for CCS Group Comments: We are concerned about three aspects of proposed 

section 146.88(a), governing injection pressure limitations. First, it 

"restricts" fractures in the injection zone "except during stimulation" rather 

than focusing on maintaining the integrity of the confining zone, which is what 

really matters for protecting USDWs. Second, it fails to refer specifically to 

the full range of potential geomechanical failure modes potentially posed by 

operations at a particular site. Third, the type of geomechanical risk that is 

addressed (initiation or propagation of fractures), is dealt with in a 

potentially arbitrary fashion (the 90% of fracture pressure limit), which may 

not be appropriate in all cases. 

Our recommended language addresses these concerns by focusing on maintaining the 

integrity of the confining zone and including tensile failure and shear failure 

as transmissivity concerns. It calls for additional geomechanical studies of 

tensile failure and shear failure only "where appropriate" because there will be 

ocations where experience or existing information will provide sufficient 

evidence to avoid the need for additional studies. The need for conducting 

additional tests and for determining which tests would be acceptable is left to 

the Director’s discretion. 

This is the same recommendation as presented by the multi-stakeholder group, in 

which the Carbon Sequestration Council participated. 

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

125
based on the fracture pressure of the injection zone, the limit is site-specific and not arbitrary. 

EPA emphasizes that injection pressure limits are important to protect against fracturing of the 

confining zone, and that the requirement at §146.88(a) that the pressure in the injection zone not 

exceed 90 percent of the fracture pressure provides a margin of safety in the well operation and 

protects USDWs from endangerment. If the Director determines, based on a review of the 

information collected as part of site characterization, that a lower injection pressure limitation is 

appropriate in order to prevent endangerment of USDWs, the Director has the authority to set a 

lower limit in the operating permit than the limit established in the rule. 

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

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

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

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

determine appropriate limits on injection. 

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

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

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

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

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

interfere with containment will not be permitted as GS sites. 

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

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

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

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

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

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

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

Letter ID: 0190 Comment ID: 24468 Letter Lines: 2756 to 2765 

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

Comment Code: 4100 2.4.1 Injection parameters 

Comment: Rule Provision: 146.88(b) 

Proposed CCS Group Recommendations: (b) Injection OF THE CO2 STREAM between the 

outermost casing protecting USDWs and the well bore is prohibited. 

Basis for CCS Group Comments: Routine injection into zones other than the target 

interval(s) should be prohibited, however, wording of this requirement is not 

clear as to which interval is being addressed. An absolute prohibition on 

injection into this annulus may also limit diagnostic or remedial options that 

could be useful. 

126
Individual Response: EPA retains the provision as proposed, and clarifies that injection 

between the casing and the well bore is prohibited. This is consistent with requirements for other 

injection well classes. 

Letter ID: 0190 Comment ID: 24469 Letter Lines: 2767 to 2779 

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

Comment Code: 4100 2.4.1 Injection parameters 

Comment: Rule Provision: 146.88(c) 

Proposed CCS Group Recommendations: (c) The owner or operator must fill the 

annulus between the tubing and the long string casing with a non-corrosive fluid 

approved by the Director. The owner or operator must maintain a positive 

pressure on the annulus. 

Basis for CCS Group Comments: Industry experience with the Class II UIC program 

does not support this requirement as proposed by EPA. 

Positive annular pressure that exceeds the operating injection pressure is not 

necessary because a leak from tubing to annulus does not have the same 

implications as in a Class I hazardous situation. 

Individual Response: EPA believes that maintaining an annulus pressure that is higher than the 

injection pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the 

annulus fluid will move into the tubing, rather than the injectate moving out of the tubing and 

potentially along the outside of the well. EPA believes this requirement is appropriate for Class 

VI wells given the potential high volumes and supercritical nature of the CO2 injectate, potential 

geomechanical stresses in the wellbore, and the potential for movement of the CO2 in the event 

of a mechanical integrity loss. 

Letter ID: 0190 Comment ID: 24470 Letter Lines: 2781 to 2785 

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

Comment Code: 4100 2.4.1 Injection parameters 

Comment: Rule Provision: 146.88(d) 

Proposed CCS Group Recommendations: Support the proposed language.. 

Basis for CCS Group Comments: Agree with EPA’s rationale 

Individual Response: EPA agrees that maintaining mechanical integrity is an essential 

component of protecting USDWs. The final rule retains this provision. 

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Letter ID: 0190 Comment ID: 24471 Letter Lines: 2787 to 2814 

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

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment) 

Comment: Rule Provision: 146.88(e) 

Proposed CCS Group Recommendations: (e) The owner or operator must install and 

use continuous recording devices to monitor: the injection pressure; the rate, 

volume, and temperature of the carbon dioxide stream and. THE OWNER OR 

OPERATOR MUST REGULARLY MONITOR the pressure on the annulus between the tubing 

and the long string casing and annulus fluid volume and. THE OWNER OR 

OPERATOR must install and use alarms and automatic down-hole shut-off 

systems, designed to alert the operator and shut-in the well when operating 

parameters such as injection rate, injection pressure, or other parameters 

approved by the Director diverge beyond ranges and/or gradients specified in the 

permit; 

Basis for CCS Group Comments: Over-pressure protection is best achieved by 

ensuring compatibility of the casing/tubing material design strength with the 

surface injection (compression) system. Down-hole shut-in devices are not 

appropriate for this application. These devices are installed in the tubing 

string and are typically near the surface of the well. They're intended to seal 

the tubing in the event of catastrophic failure of the wellhead. These devices 

would provide little if any protection to USDWs. Is not practicable to install 

these devices deep within the well (e.g. shortly above the packer). Additionally 

these devices create a restriction on running other tools like logging tools in 

the well and therefore could limit an operators ability to do required 

monitoring and diagnostic work. Lastly, these devices require periodic testing 

and maintenance which could require either pulling the device by wireline or by 

pulling the entire tubing string depending on the type of device installed. 

Either of these activities would be disruptive and costly to the overall project 

operations. 

Individual Response: EPA acknowledges that proper design of the well, including appropriate 

materials and emplacement of casing and tubing, is essential to proper operation of the well. 

Such design, however, does not eliminate the possibility of failure, e.g., due to overpressurization as suggested by the commenter. EPA believes that a multiple-barrier approach, 

which includes appropriate well design as required at §146.86, suitable injection pressure limits 

as required at §146.88(a), and automatic shut-off systems, as required at §146.88(e), is necessary 

to ensure protection of USDWs from endangerment from the risks associated with CO2 GS. 

Landing nipples, which are machined portions of the tubing that allow the seating of 

components–such as safety valves—at a later time, can be used to deploy safety valves after the 

initial well completion. EPA believes, however, that if the shut-off system is not deployed until 

128
the failure occurs, CO2 will be free to flow out of the well until the shut-off valve is deployed. 

Since installing the new shut-off system will require getting the device to the site, setting up a 

rig, and deploying the device down the well, a significant amount of time could elapse following 

an adverse event before the well is sealed. EPA believes that the risks of uncontrolled CO2 flow 

are too great to be allowed for such a length of time. 

As described above, EPA will not require automatic down-hole shut-off devices for onshore 

Class VI wells since it is not necessary in all cases to ensure protection of USDWs from 

endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or operators of 

onshore Class VI wells install automatic surface shut-off devices. The rule affords Director's 

discretion to mandate automatic down-hole shut-off devices in onshore situations that may 

warrant their use. The rule requires, at §146.88(e)(3), that owners or operators of offshore wells 

within State territorial waters install automatic down-hole shut-off systems. 

Letter ID: 0190 Comment ID: 24472 Letter Lines: 2816 to 2827 

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

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment) 

Comment: Rule Provision: 146.88(f) 

Proposed CCS Group Recommendations: (f) If an down-hole automatic shutdown 

is triggered or a loss of mechanical integrity is discovered, the owner or 

operator must immediately investigate and identify as expeditiously as possible 

the cause of the shutoff. If, upon such investigation, the well appears to 

be lacking mechanical integrity, or if monitoring required under paragraph (e) 

of this section otherwise indicates that the well may be lacking mechanical 

integrity, the owner or operator must: 

Basis for CCS Group Comments: Revisions made here to make this subsection 

conform with changes to 146.88(e) above. 

Individual Response: As described above, EPA will not require automatic down-hole shut-off 

devices for onshore Class VI wells since it is not necessary in all cases to ensure protection of 

USDWs from endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or 

operators of onshore Class VI wells install automatic surface shut-off devices. The rule affords 

Director's discretion to mandate automatic down-hole shut-off devices in onshore situations that 

may warrant their use. The rule requires, at §146.88(e)(3), that owners or operators of offshore 

wells within State territorial waters install automatic down-hole shut-off systems. Please see the 

final rule and preamble for additional information on EPA's final approach. 

Letter ID: 0190 Comment ID: 24473 Letter Lines: 2829 to 2835 

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

Comment Code: 4000 2.4 Proposed Injection Well Operating Requirements (40 CFR 146.88) 

129
Comment: Rule Provision: 146.88(f)(3) 

Proposed CCS Group Recommendations: (3) Notify the Director within 24 hours OF 

DISCOVERY; 

Basis for CCS Group Comments: Clarifying revision to (3) will make compliance 

feasible for operators. 

Individual Response: The final rule text at §146.88(f) now reads, "If a shutdown (i.e., downhole or at the surface) is triggered or a loss of mechanical integrity is discovered." Therefore the 

notice required at §146.88(f)(3) must be provided within 24 hours of an automatic shut-off 

device being triggered or a loss of mechanical integrity being discovered. EPA believes this 

provision is necessary to ensure timely response to potential USDW endangerment. 

Letter ID: 0190 Comment ID: 24474 Letter Lines: 2837 to 2841 

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

Comment Code: 4500 2.5 Proposed Mechanical Integrity Testing (MIT) Requirements (40 CFR 

146.89) 

Comment: Rule Provision: 146.89(a) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment and the final rule retains the text at 

146.89(a) as proposed. 

Letter ID: 0190 Comment ID: 24475 Letter Lines: 2843 to 2857 

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

Comment Code: 4520 2.5.1 Continuous internal mechanical integrity monitoring (seeking 

comment) 

Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

Comment: Rule Provision: 146.89(b) 

Proposed CCS Group Recommendations: (b) To evaluate the absence of significant 

leaks under paragraph (a)(1) of this section, owners or operators must, 

following an initial annulus pressure test, continuously monitor AND RECORD AT 

LEAST DAILY, ANNULUS PRESSURE AND VOLUMES OF FLUID ADDED TO OR 

REMOVED FROM 

injection pressure, rate, injected volumes, and pressure on the annulus 

130
between the tubing and long stem string casing and annulus fluid volume as 

specified in §146.88 (e); 

Basis for CCS Group Comments: We recommend continuous monitoring, but do not 

find continuous recording necessary as Class II requirements have proven 

sufficient. The alternative of continuous monitoring, which will alert operator 

to any problems, and daily recording to allow for daily check of wells. This is 

consistent with successful Class II operating experience. 

Individual Response: EPA agrees with the commenter regarding the importance of 

demonstrating internal mechanical integrity (MI). Class VI injection wells will be equipped with 

dedicated computer-based continuous pressure monitoring devices, in concert with the shut-off 

systems required for GS wells, which typically take readings several times per second (i.e., more 

frequently than daily) and record them electronically in a computer system. 40 CFR 

§146.91(a)(2) requires that monthly averages of the continuous annulus monitoring be reported 

on a semiannual basis. 

Letter ID: 0190 Comment ID: 24476 Letter Lines: 2859 to 2876 

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

Comment Code: 4540 2.5.2 Proposed external MIT requirements 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: Rule Provision: 146.89(c) 

Proposed CCS Group Recommendations:(c) At least once per year, the owner or 

operator must confirm the absence of significant fluid movement under paragraph 

(a)(2) of this section USING A METHOD ACCEPTABLE TO THE DIRECTOR (E.G. 

INCLUDING 

DIAGNOSTIC SURVEYS SUCH AS OXYGEN-ACTIVATION LOGGING OR 

TEMPERATURE OR NOISE 

LOGS). (1) A tracer survey such as oxygen-activation logging; (2) A 

temperature or noise log; or (3) A casing inspection log, if required by the 

Director. 

Basis for CCS Group Comments: Revised text supports a performance-based approach 

and allows the development and use of new technologies as they become available. 

Cement circulation to the surface is not necessary because having the open 

annulus above the top of cement allows regular monitoring of annular pressure 

which could indicate leakage. 

We recommend deletion of subsection (3) because it would require that the tubing 

be pulled at significant cost and risk of uncontrolled releases. 

Individual Response: EPA believes that the MITs described in 146.89(c) of the rule (an 

approved tracer log or temperature or noise logs) are effective methods to demonstrate external 

131
MI, provide an important early warning of potential problems in the injection well system, and 

represent standard techniques that have been used successfully by the drilling industry and for 

the UIC Program for decades. The Agency notes that the regulations do provide the Director 

flexibility at §146.89(e) to approve the use of alternative MIT methods. 

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement 

behind the casing, but clarifies that it can be used to determine the presence or absence of 

corrosion of the long-string casing, and is required if the Director determines that it is necessary 

based on site-specific information. EPA has revised the final GS rule to require that the 

frequency of the casing inspection log must be specified in the approved testing and monitoring 

plan. See §146.89(d). 

Letter ID: 0190 Comment ID: 24477 Letter Lines: 2878 to 2894 

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

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: Rule Provision: 146.89(d) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Rule Provision: 146.89(e) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Rule Provision: 146.89(f) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comments and the final rule retains the text as 

proposed. 

Letter ID: 0190 Comment ID: 24478 Letter Lines: 2896 to 2912 

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

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment) 

Comment: Rule Provision: 146.90 [Introductory text] 

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Proposed CCS Group Recommendations: (A) BASED ON A SITE-SPECIFIC ASSESSMENT 

OF 

THE POTENTIAL FOR FLUID MOVEMENT FROM THE INJECTION WELL OR 

INJECTION ZONE, AND 

ON THE POTENTIAL VALUE OF MONITORING WELLS TO DETECT SUCH 

MOVEMENT, the owner or 

operator of a Class VI well must prepare, maintain, and comply with a testing 

and monitoring plan to verify that the geologic sequestration project is 

operating as permitted and is not endangering USDWs. THE TESTING AND 

MONITORING PLAN MUST BE SUBMITTED WITH THE PERMIT APPLICATION, FOR 

DIRECTOR 

APPROVAL AND INCLUDE A DESCRIPTION OF HOW THE OWNER OR OPERATOR 

WILL MEET THE 

REQUIREMENTS OF THIS SECTION; 

Basis for CCS Group Comments: Drilling monitoring wells should be carefully 

considered since each well introduces a potential pathway for fluid movement. In 

addition the cost of adding multiple wells could create a barrier to CCS 

development, while providing limited information on actual movement of the CO2 

stream. 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. See 

the final rule and preamble for further discussion on EPA's final approach. 

EPA anticipates that the testing and monitoring plan will address site-specific geologic factors, 

modeling, and risk-assessment. EPA is developing guidance on how best to develop the various 

required project plans, including the testing and monitoring plan. The guidance can be found on 

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

EPA believes that monitoring using wells in the injection zone, e.g., for pressure monitoring as 

required at §146.90(g)(1), can be safely performed if the wells are constructed to prevent flow 

between the injection zone and USDWs or other layers above the confining zone. Such 

construction technologies exist and have been used in the oil and gas industry for years. EPA 

believes that properly constructed monitoring wells will be a safe way to obtain the data that is 

essential to ensure that the injected CO2 remains confined in the injection zone and that pressure 

changes are not causing movement of formation or other fluids. To mitigate the risk of fluid 

movement, EPA requires owners and operators to submit a testing and monitoring plan that 

describes how the owner or operator plans to site and construct monitoring wells. EPA is 

developing guidance on well construction that will include recommendations for monitoring well 

construction. The guidance will be available on EPA’s website at 

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

Letter ID: 0190 Comment ID: 24479 Letter Lines: 2914 to 2941 

133
Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 

CFR 146.90) 

Comment: Rule Provision: 146.90(a) & (b) 

Proposed CCS Group Recommendations: (B) THE TESTING AND MONITORING PLAN 

MUST, AT 

A MINIMUM, INCLUDE: 

(a) (1) analysis of the carbon dioxide stream with sufficient frequency to 

yield data representative of its chemical and physical characteristics; 

(b) (2) Installation and use, except during well workovers as defined in 

section 146.88(d), of continuous monitoring devices (INCLUDING DIGITAL DEVICES 

CAPTURING PERIODIC DATA) to monitor injection pressure, rate and volume; AND 

RECORD AT LEAST DAILY the pressure on the annulus between the tubing and the 

long strong casing; 

(3) A DEMONSTRATION OF EXTERNAL MECHANICAL INTEGRITY PURSUANT TO 

§146.89(C) 

UNTIL THE WELL IS PLUGGED; 

(4) MONITORING OF THE PRESSURE BUILDUP IN THE INJECTION ZONE 

ANNUALLY, INCLUDING 

AT A MINIMUM, A SHUT DOWN OF THE WELL FOR A TIME SUFFICIENT TO 

CONDUCT A VALID 

OBSERVATION OF THE PRESSURE FALL-OFF CURVE AT LEAST ONCE EVERY FIVE 

YEARS; AND 

(5) A QUALITY ASSURANCE PLAN FOR ALL TESTING AND MONITORING 

REQUIREMENTS. 

Basis for CCS Group Comments: There is concern regarding what constitutes 

continuous monitoring. Industry agrees that regular monitoring of the parameters 

identified by EPA is appropriate. Experience with CO2 EOR strongly shows that 

daily monitoring of most of these parameters is adequate (exceptions to this 

would be on a site-specific basis). Recording should generally be done on a 

daily basis and reporting on a semi-annual basis. 

Individual Response: EPA believes that continuous pressure monitoring of GS wells, as 

required at §146.88(e), is important and appropriate because the potentially corrosive nature of 

CO2 streams in the presence of water makes it critical to immediately identify corrosion-related 

well mechanical integrity loss. Class VI injection wells must be equipped with dedicated 

computer-based continuous pressure monitoring devices (in concert with the Director-approved 

shut-off systems required for GS wells), which typically take readings several times per second 

and record them electronically in a computer system.. 

134
EPA believes that a frequency of five years, as specified at §146.90(f), is an appropriate interval 

for pressure fall-off testing (particularly given the suite of tests operators will perform on the 

well and the site). EPA clarifies that the Director may require more frequent pressure fall-off 

tests at a specific project if necessary, based on site-specific circumstances. Pressure fall-off tests 

may be conducted in conjunction with other well performance tests (i.e., mechanical integrity 

testing) to ensure safe and effective operations. All monitoring data collected, including 

information from pressure fall-off tests, will be incorporated in AoR reevaluations at least every 

five years. EPA disagrees that the rule should provide specifics of the testing to the degree 

suggested, however. 

EPA clarifies that periodic MITs will not be required following plugging of the well. 

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

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

preamble for further discussion on EPA's final approach. 

Letter ID: 0190 Comment ID: 24480 Letter Lines: 2943 to 2992 

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

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: Rule Provision: 146.90(c) 

Proposed CCS Group Recommendations: (C) WHERE APPROPRIATE, THE TESTING AND 

MONITORING PLAN SHALL ALSO INCLUDE: 

(1) CONTINUOUS MONITORING FOR PRESSURE CHANGES IN AN APPROPRIATELY 

POROUS AND 

PERMEABLE FORMATION OVERLYING THE CONFINING ZONE.; 

(2) THE USE OF INDIRECT, GEOPHYSICAL TECHNIQUES TO DETERMINE THE 

POSITION OF THE 

CO2 STREAM FRONT, THE WATER QUALITY IN A DESIGNATED FORMATION, OR 

TO PROVIDE 

OTHER SITE SPECIFIC DATA; 

(3) PERIODIC MONITORING OF WATER QUALITY IN AN APPROPRIATELY POROUS 

AND 

PERMEABLE FORMATION OVERLYING THE INJECTION ZONE; 

(4) PERIODIC MONITORING OF WATER QUALITY IN ONE OR MORE USDWS; 

c (5) Corrosion monitoring of the well materials for loss of mass, 

thickness, cracking, pitting and other signs of corrosion performed and recorded 

AT LEAST on a quarterly WHICH MAY BE MODIFIED TO BE LESS FREQUENT AS 

135
APPROVED BY THE DIRECTOR BASED ON CONSTRUCTION MATERIALS, 

OPERATING CONDITIONS, 

AND MONITORING HISTORY to ensure that the well components meet the minimum 

standards for material strength and performance set forth in §146.86(b) by: 

(1) (I) Placing ANALYZING coupons of the well construction materials 

placed in contact with the carbon dioxide stream; or 

(2) (II) Routing the carbon dioxide stream through a loop constructed with 

the material used in the well AND INSPECTING THE MATERIALS IN THE LOOP; or 

(3) (III) Using an alternative method, MATERIALS, OR TIME PERIOD approved by 

the Director; 

(6) ANY ADDITIONAL TESTING AND MONITORING NECESSARY TO SUPPORT 

MODELING THE 

EXTENT OF THE CARBON DIOXIDE PLUME AND THE POSITION OF THE PRESSURE 

FRONT; AND 

(7) ANY ADDITIONAL TESTING AND MONITORING NECESSARY TO DETERMINE 

WHETHER FLUID 

MOVEMENT IS OCCURRING INTO OR BETWEEN USDWS THAT WOULD ENDANGER 

A USDW. 

Basis for CCS Group Comments: There should be no need for corrosion monitoring 

of most injected CO2 streams because those streams will typically overwhelmingly 

CO2 and dry thus having no corrosive properties. Industry experience with 

production, transportation, and injection of dry CO2 strongly illustrates the 

non-corrosive nature of this type of CO2 stream. 

This proposal revises the provision to make it a requirement only where 

appropriate based on the materials of construction and characteristics of the 

injected CO2 stream and other factors. 

The corrosion provisions are included in subsection (c)(5). 

Individual Response: EPA believes that quarterly corrosion monitoring of GS wells is 

necessary. CO2 in the presence of water (including water with NOx, SOx, and H2S impurities) 

can be corrosive to well materials and cements. Thus, although a CO2 stream may be dry, the 

potential for corrosion of well materials down-hole, where the injectate can potentially mix with 

water in the target formation, must be considered. 

Several laboratory studies and a limited number of field studies have investigated and 

characterized the effects of carbonic acid on well materials. Laboratory studies (e.g., Kutchko et 

al., 2007; Kutchko et al., 2008) consistently identify alterations (typically carbonation) of cement 

as the result of interactions between cement and CO2-saturated brine. 

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Currently, there are only a few analyses of cement from wells that have been in prolonged 

contact with CO2 in actual field (down-hole) conditions. Evaluation of cement from a well at the 

Scurry Area Canyon Reef Operators Committee (SACROC) site showed alteration, but did not 

show degradation that compromised the structural integrity of the cement (Carey et al., 2007). In 

another study, cement samples were collected and analyzed from a CO2 production well in a 

natural CO2 reservoir in Colorado exposed to a CO2-water down-hole environment for 30 years 

(Crow et al., 2008). The study found evidence of reaction between the CO2-rich water and the 

cement. 

Oil industry research also addresses the effects of corrosion of steel tubing and pipes. Lopez et 

al. (2003) noted that 60 percent of oilfield failures are related to the effects of carbonic acid from 

produced brines on carbon and low alloy steels. 

Laboratory investigation of cement alteration/degradation is an ongoing research area. Few fieldbased studies have been completed to date. The laboratory and field studies currently available 

suggest that corrosion problems can be managed; however, there is not a large enough body of 

research to rule out potential corrosion problems of steel components of injection wells. The 

IPCC (2005) report on carbon dioxide capture and storage reviewed oil and gas industry 

experience with gas injection wells, close industry analogues to CO2 injection wells. The report 

stated that, while the design of CO2 injection wells will be very similar to gas injection wells, 

most down-hole components of the CO2 injection wells will “need to be upgraded for higher 

pressure ratings and corrosion resistance.” Given the pressure and corrosion considerations, 

anticipated long lifespan of a GS well and the difficulties that would be associated with a 

corrosion-related well failure, EPA believes that corrosion monitoring in the down-hole 

environment is justified. For these reasons, the final rule requires quarterly corrosion monitoring 

at §146.90(c). 

EPA maintains that plume tracking and pressure monitoring are key components of monitoring 

at GS sites. A rigorous plume tracking and pressure monitoring scheme, such as one that meets 

the requirements at §146.90(g), is imperative for ensuring that the CO2 plume is contained 

within the injection zone. Pressure monitoring in the injection zone is necessary to track the 

development and movement of the pressure front and CO2 plume. When combined with 

information on temperature, pressure data provide an indication of the phase (e.g., gas, 

supercritical) and distribution of the injected CO2. 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 also believes that the ground water geochemical monitoring outlined in §146.90(d) will 

maximize protection of USDWs from endangerment at GS sites. Direct geochemical sampling is 

an important part of a monitoring program. See the final rule and preamble for further discussion 

on EPA's final approach. 

Letter ID: 0190 Comment ID: 24481 Letter Lines: 2994 to 3009 

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

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Comment Code: 4660 2.6.6 Geochemical monitoring 

Comment: Rule Provision: 146.90(d) 

Proposed CCS Group Recommendations: (d) Periodic monitoring of the ground 

water quality and geochemical changes above the confining zone(s) that may be a 

result of carbon dioxide movement through the confining zone or additional 

identified zones: 

(1) The location and number of monitoring wells must be based on specific 

information about the geologic sequestration project, including injection 

rate and volume, geology, the presence of artificial penetrations and other 

factors; 

(2) The monitoring frequency and spatial distribution of monitoring wells must 

be based on baseline geochemical data that has been collected under § 146.82(a) 

(6) and any modeling results in the area of review evaluation required by § 

146.84(b); 

Individual Response: EPA did not make the suggested changes, but agrees that monitoring 

plans and methods need to be site-specific and based on baseline data and data collected 

throughout operations. EPA believes that the monitoring requirements for GS sites at §146.90 

provide an appropriate level of flexibility in structuring a testing and monitoring plan that 

protects USDWs from endangerment. 

The final regulation provides for flexibility in: 1) methodologies used to collect these data, 2) the 

spatial resolution at which the data should be collected, and 3) how often the data should be 

collected. The number and placement of monitoring wells will be based on site-specific 

information such as the calculated AoR, injection rate and volume, site geology, baseline data, 

and the presence of artificial penetrations within the AoR. In some instances, there may be a 

limited number of options for complying with EPA's minimum requirements. For example, 

monitoring for geochemical changes will require use of monitoring wells and collection of 

groundwater samples for chemical analysis. Many options currently exist for complying with 

other requirements, such as tracking the position of the plume and pressure front within the 

injection zone. 

Flexibility is also provided regarding how to monitor for the specific data required by the final 

rule. The testing and monitoring plan is developed by the owner or operator in consultation with 

the Director and is designed to ensure that a detailed, Director-approved document describing 

how monitoring will be conducted during the lifetime of the project exists. 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 

138
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. 

Letter ID: 0190 Comment ID: 24482 Letter Lines: 3011 to 3022 

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

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 

CFR 146.90) 

Comment: Rule Provision: 146.90(e) & (f) 

Proposed CCS Group Recommendations: (e) A demonstration of external mechanical 

integrity pursuant to § 146.89(c) at least once per year throughout the duration 

of the geologic sequestration project; 

(f) A pressure fall-off test at least once every five years unless more frequent 

testing is required by the Director based on site specific information; 

Basis for CCS Group Comments: Redundant to section 146.89 

These issues are addressed in recommended subsection (b)(3) and (4). 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

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

the final rule and preamble for further discussion on EPA's final approach. EPA adds that the 

purpose of including all testing and monitoring requirements in §146.90 is to clarify and to 

specify the content of the required testing and monitoring plan. 

Letter ID: 0190 Comment ID: 24483 Letter Lines: 3024 to 3036 

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: Rule Provision: 146.90(g) 

Proposed CCS Group Recommendations: (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); 

Basis for CCS Group Comments: Monitoring outside of the injection zone provides 

little information of value for tracking and monitoring the injected plume. 

Examples of how to test and monitor could be included in the Preamble but need 

139
not be included in the rule itself. 

Individual Response: EPA has revised this requirement in the final rule. The final GS 

regulation, at §146.90(g)(1), requires all GS project owners or operators to monitor for pressure 

changes in the injection zone. EPA believes that pressure monitoring in the injection zone is 

necessary to track the development and movement of the pressure front and CO2 plume. 

Pressure monitoring within the injection zone is necessary because any such monitoring above 

the confining zone would not detect movement of the pressure front unless a breach of the 

confining zone occurs. EPA believes that monitoring using wells in the injection zone (i.e., that 

penetrate the confining zone) can be safely performed if the wells are constructed to prevent flow 

between the injection zone and USDWs or other layers above the confining zone. Such 

construction technologies exist and have been used in the oil and gas industry for years. EPA 

believes that the benefits of monitoring in the injection formation outweigh the manageable risk 

of those monitoring wells serving as conduits for fluid movement. EPA adds that owners or 

operators may consider performing additional pressure monitoring in wells that are above the 

confining zone (e.g., in the same wells used to perform ground water quality monitoring required 

at §146.90(d)) to provide additional verification that no pressure changes are occurring above the 

confining zone due to CO2 leakage. Monitoring also identifies needed remedial actions, provides 

inputs for AoR reevaluation modeling, and targets 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. 

EPA acknowledges that, at certain sites, there may be a need for more or different monitoring 

schemes (which may include monitoring in the confining zone), and adds that it is important to 

balance the need for adequate monitoring that ensures USDW protection from endangerment 

against too many artificial penetrations which could serve as conduits for fluid migration. Sitespecific testing and monitoring plans should describe the proposed monitoring regime, which 

must be approved by the Director. 

Flexibility is also provided regarding how to monitor for the specific data required by the final 

rule. The testing and monitoring plan is developed by the owner or operator in consultation with 

the Director and is designed to ensure that a detailed, Director-approved document describing 

how monitoring will be conducted during the lifetime of the project exists. 

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. 

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Letter ID: 0190 Comment ID: 24484 Letter Lines: 3038 to 3054 

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: Rule Provision: 146.90(h) 

Proposed CCS Group Recommendations: (h) At the Director’s discretion, surface 

air monitoring and/or soil gas monitoring to detect movement of carbon dioxide 

that could endanger a USDW. 

(1) The testing and monitoring plan must be based on potential vulnerabilities 

within the area of review; 

(2) The monitoring frequency and spatial distribution of surface air monitoring 

and/or soil gas monitoring must reflect baseline data and the monitoring plan 

must include how the proposed monitoring will yield useful information on the 

area of review delineation and/or compliance with standards under 40 CFR 

144.12; 

Basis for CCS Group Comments: In most situations soil and air monitoring does 

not provide an effective method of protecting USDWs. 

Individual Response: EPA acknowledges that air and soil gas monitoring to ensure USDW 

protection is not necessary at all GS sites and agrees that the decision to use surface monitoring 

and the selection of monitoring methods for the purpose of USDW protection will be sitespecific. 

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. EPA also 

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. 

In the final rule, at §146.90(h), the decision to require such monitoring as an additional measure 

to ensure USDW protection rests with 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). 

Letter ID: 0190 Comment ID: 24485 Letter Lines: 3056 to 3067 

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

141
Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment) 

Comment: Rule Provision: 146.90(i) & (j) 

Proposed CCS Group Recommendations: (i) Any additional monitoring, as required 

by the Director, necessary to support, upgrade, and improve computational 

modeling of the area of review evaluation required under § 146.84(b) and to 

determine compliance with standards under 40 CFR 144.12; and 

(j) A quality assurance and surveillance plan for all testing and monitoring 

requirements. 

Basis for CCS Group Comments: These issues are addressed in subsection (c)(6) 

and (b)(5) respectively. 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. See 

the final rule and preamble for further discussion on EPA's final approach. 

Letter ID: 0190 Comment ID: 24486 Letter Lines: 3069 to 3075 

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

Comment Code: 4760 2.7.6 Proposed reporting frequency (seeking comment) 

Comment: Rule Provision: 146.91(a) 

Proposed CCS Group Recommendations: (a) Semi-annual OR LESS FREQUENT AT THE 

DISCRETION OF THE DIRECTOR reports containing: 

Basis for CCS Group Comments: Over the life of the project, the Director may 

decide that less reporting is acceptable 

Individual Response: EPA is retaining the semi-annual reporting requirement in the final rule at 

§146.91(a) in order to ensure that permitting authorities can maintain proper oversight of GS 

projects, particularly in the early stages of rule implementation and deployment of GS 

technologies. The Agency also clarifies that permitting authorities may choose to require more 

frequent reporting, at the discretion of the Director. See the final rule and preamble for further 

discussion on EPA's final approach to reporting and recordkeeping. 

EPA is using an adaptive approach to regulating GS. The Agency plans to, every six years, 

collect and review data on GS projects, including operational data, 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. 

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Letter ID: 0190 Comment ID: 24487 Letter Lines: 3077 to 3085 

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

Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

Comment: Rule Provision: 146.91(a)(1) 

Proposed CCS Group Recommendations: (1) Any SIGNIFICANT changes to the physical, 

chemical and other relevant characteristics of the carbon dioxide stream from 

the proposed operating data; 

Basis for CCS Group Comments: (1) Technical clarification. Significance can be 

determined by a statistical analysis of the data. Rules should recognize that 

there will be minor variations in many data sets over time. 

Individual Response: EPA retained this provision as proposed. The final rule at §146.91(a)(3) 

requires reporting of all exceedances of operating parameters. EPA disagrees with the suggestion 

to report only "significant" exceedances. Making a determination as to whether an exceedance is 

"significant" is not the purpose of the requirement. EPA believes that the ability of an operator to 

consistently meet operating requirements and avoid exceedances provides evidence of a wellmanaged GS project that is in compliance with the Class VI permit. If multiple exceedances 

occur, the Director should be aware of such occurrences, and that information will aid in his/her 

determination of whether these indicate problems at the site, and what is the appropriate course 

of action (e.g., a well workover, modification of operating parameters, or imposition of a 

penalty) to remediate such problem(s). 

Letter ID: 0190 Comment ID: 24488 Letter Lines: 3087 to 3098 

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

Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

Comment: Rule Provision: 146.91(a)(3) & (4) 

Proposed CCS Group Recommendations: (3) A description of any SIGNIFICANT event 

that exceeds operating parameters for annulus pressure or injection pressure as 

specified in the permit; 

(4) A description of any SIGNIFICANT event which triggers a shutdown device 

required pursuant to §146.88(e) and the response taken; 

Basis for CCS Group Comments: EPA should consider some significance threshold on 

reporting these events to avoid reporting events that would be of limited 

interest or consequence. 

Individual Response: EPA retained this provision as proposed. The final rule at §146.91(a)(3) 

requires reporting of all exceedances of operating parameters. EPA disagrees with the suggestion 

143
to report only "significant" exceedances. Making a determination as to whether an exceedance is 

"significant" is not the purpose of the requirement. EPA believes that the ability of an operator to 

consistently meet operating requirements and avoid exceedances provides evidence of a wellmanaged GS project that is in compliance with the Class VI permit. If multiple exceedances 

occur, the Director should be aware of such occurrences, and that information will aid in his/her 

determination of whether these indicate problems at the site, and what is the appropriate course 

of action (e.g., a well workover, modification of operating parameters, or imposition of a 

penalty) to remediate such problem(s). 

Letter ID: 0190 Comment ID: 24489 Letter Lines: 3100 to 3104 

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

Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment) 

Comment: Rule Provision: 146.91(b) & (c) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment and the final rule retains the text as 

proposed. See the final rule and preamble for further discussion on EPA's final approach to 

reporting and recordkeeping. 

Letter ID: 0190 Comment ID: 24490 Letter Lines: 3106 to 3131 

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

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: Rule Provision: 146.92(a) 

Proposed CCS Group Recommendations: (a) Prior to the well plugging, the owner or 

operator must flush each Class VI injection well with a buffer fluid, determine 

bottomhole reservoir pressure, and perform a final EXTERNAL mechanical integrity 

test OF ANY RELEVANT WELLBORE MATERIALS REMAINING. 

Basis for CCS Group Comments: Many of the components that would be tested by an 

internal MIT are removed or tested during the plugging process. 

Rule Provision: 146.92(b) 

Proposed CCS Group Recommendations: Support the proposed language. 

144
Basis for CCS Group Comments: Agree with EPA’s rationale. 

Rule Provision: 146.192(b)(2) & (5) 

Proposed CCS Group Recommendations: (2) Appropriate testing methods to ensure 

FINAL EXTERNAL mechanical integrity as specified in §146.89(C); ... 

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

material must be SUITABLE FOR USE with the carbon dioxide stream; and 

Basis for CCS Group Comments: Many of the components that would be tested by an 

internal MIT are removed or tested during the plugging process. 

Individual Response: Regarding the suggested edit at 146.92(b)(2), EPA agrees that only an 

external MIT is required, and has modified the GS rule at §146.92(a) and 146.92(b) to require 

owners or operators to perform a final external mechanical integrity test prior to the well 

plugging. 

Regarding the edit at 146.92(b)(5), EPA believes, considering the potentially corrosive nature of 

CO2 when it is in contact with water, that the requirement that the material must be compatible 

with the CO2 stream is appropriate. The final rule retains this requirement. 

Letter ID: 0190 Comment ID: 24491 Letter Lines: 3133 to 3137 

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

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: Rule Provision: 146.92(c) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the commenter’s support and the final rule retains this 

approach. 

Letter ID: 0190 Comment ID: 24492 Letter Lines: 3139 to 3149 

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

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

145
Comment: Rule Provision: 146.92(d) 

Proposed CCS Group Recommendations: (d) Plugging report. Within 60 days after 

plugging the owner or operator must submit a plugging report to the Director. 

If the semi-annual report is due less than 15 days after completion of 

plugging, then the report must be submitted within 60 days after plugging. The 

report must be certified as accurate by the owner or operator and by the person 

who performed the plugging operation (if other than the owner or operator.) 

Basis for CCS Group Comments: The proposed change will simplify and clarify a 

provision that is unnecessarily complicated. 

Individual Response: EPA has revised the text at §146.92(d) to reduce confusion. The final rule 

text reads, "Within 60 days after plugging the owner or operator must submit a plugging report to 

the Director." 

Letter ID: 0190 Comment ID: 24493 Letter Lines: 3151 to 3160 

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

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

Comment: Rule Provision: 146.93(a)(1) 

Proposed CCS Group Recommendations: (1) The owner or operator must submit the 

post-injection site care and site closure plan as a part of the permit 

application to be approved by the Director. SHALL CONTINUE TO CONDUCT 

MONITORING AS SPECIFIED IN THE DIRECTOR-APPROVED POST-INJECTION SITE 

CARE AND 

SITE CLOSURE PLAN, PURSUANT TO THE PERFORMANCE BASED CRITERIA 

DESCRIBED IN 

146.93(B)(3). 

Basis for CCS Group Comments: Revisions here reflect changes to §146.93(b)(3) 

Individual Response: EPA disagrees with the suggested changes, and disagrees that the postinjection monitoring period should be strictly performance-based. The Agency agrees that there 

will be limited 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, and has included 

requirements in the final Class VI rule at §146.93(c) for an owner or operator to substantially 

demonstrate that an alternative time frame ensures the protection of USDWs. However, EPA 

anticipates that a default timeframe for post-injection site care will necessary for most GS sites to 

ensure the protection of USDWs. A 50-year post-injection site care timeframe represents a 

reasonable and protective monitoring period based on a review of research studies, industry 

reports, and existing environmental programs, and evaluation of public comments. For this 

reason, the final GS regulation includes a provision that the Director may, at his or her 

146
discretion, shorten the post-injection site care timeframe if the owner or operator can 

demonstrate that the GS project does not pose an endangerment to USDWs, as specified in 

§146.93(b)(2). Such a demonstration will be site-specific, and based on pressure monitoring and 

USDW impacts. 

The GS rule requires owners or operators to submit a post-injection site care and site closure plan 

as part of the permit application, as specified in §146.82(a), in order to outline how these 

activities will be performed and how non-endangerment of USDWs will be demonstrated 

throughout the post-injection site care period. 

Letter ID: 0190 Comment ID: 24494 Letter Lines: 3162 to 3180 

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

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

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

Comment: Rule Provision: 146.93(a)(2) 

Proposed CCS Group Recommendations: (2) The post-injection site care and site 

closure plan must include the following information: 

(i) The pressure differential between pre-injection and predicted post-injection 

pressures in the injection zone; 

(ii) The predicted position of the carbon dioxide plume and associated pressure 

front at site closure as demonstrated in the area of review evaluation required 

under § 146.84(b); 

(iii) A description of post-injection monitoring location, methods, and proposed 

frequency; and 

(iv) A proposed schedule for submitting post-injection site care monitoring 

results to the Director. 

Basis for CCS Group Comments: Revisions here reflect changes to §146.93(b)(3) 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

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

the final rule and preamble for further discussion on EPA's final approach. 

Letter ID: 0190 Comment ID: 24495 Letter Lines: 3182 to 3186 

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

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

147
Comment: Rule Provision: 146.93(a)(3) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA agrees that a post-injection site care monitoring plan is an important 

tool for GS and anticipates that, in some cases, the appropriate post-injection monitoring strategy 

may end up being different than initially projected and there may be a need to amend the postinjection site care and site closure plan. EPA is requiring that, upon the cessation of injection, the 

owner or operator submit an amended post-injection site care and site closure plan or 

demonstrate to the Director that no changes to the original post-injection site care and site 

closure plan are necessary (146.93(a)(3)). EPA is not requiring formal periodic review and 

updates to the PISC and site closure plan throughout the injection phase. 

Letter ID: 0190 Comment ID: 24496 Letter Lines: 3188 to 3195 

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

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

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

Comment: Rule Provision: 146.93(a)(4) 

Proposed CCS Group Recommendations: 4) AT ANY TIME DURING THE POST-INJECTION 

SITE CARE PHASE, The owner or operator may modify and resubmit the postinjection site care and site closure plan for the Director’s approval within 30 

days of such change. 

Basis for CCS Group Comments: Technical Clarification. 

Individual Response: EPA agrees that a post-injection site care monitoring plan is an important 

tool for GS and anticipates that, in some cases, the appropriate post-injection monitoring strategy 

may end up being different than initially projected and there may be a need to amend the postinjection site care and site closure plan. EPA is requiring that upon the cessation of injection, the 

owner or operator submit an amended post-injection site care and site closure plan or 

demonstrate to the Director that no changes to the original post-injection site care and site 

closure plan are necessary (146.93(a)(3)). EPA is not requiring formal periodic review and 

updates to the PISC and site closure plan throughout the injection phase. EPA does not expect 

that changes to this plan would be implemented until injection operations cease. EPA envisions 

that owners or operators would take into account similar considerations that guide updates to 

other project plans, e.g., monitoring and operational data and results of AoR reevaluations. EPA 

adds that, if any monitoring or other site data indicate a need for amending the post-injection site 

care plan, the owner or operator is expected to amend the plan accordingly under §146.93(a)(3). 

EPA adds that, in the final rule, it has revised the text at §146.93(a)(4) as follows: "At any time 

148
during the life of the geologic sequestration project, the owner or operator may modify and 

resubmit the post-injection site care and site closure plan for the Director’s approval within 30 

days of such change." 

EPA is issuing guidance on development and updating of the GS project plans, including the 

post-injection site care and site closure plan. The guidance will be available on EPA's web site at 

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

Letter ID: 0190 Comment ID: 24497 Letter Lines: 3197 to 3216 

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

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

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

Comment: Rule Provision: 146.93(b) 

Proposed CCS Group Recommendations: (b) The owner or operator shall monitor the 

site following the cessation of injection to show the position of the carbon 

dioxide plume and pressure front and demonstrate that USDWs are not being 

endangered. 

(1) The owner or operator shall continue to conduct monitoring as specified in 

the Director-approved post-injection site care and site closure plan, UNTIL 

CLOSURE IS AUTHORIZED PURSUANT TO 146.93(B)(3). 

Basis for CCS Group Comments: EPA should also reconsider its proposed 50-year 

default period for post-injection site care. EPA offers no rationale for this 

arbitrarily-selected period of 50 years. Establishing a fixed and unusually long 

time period may create a significant barrier for operators considering entry 

into CCS operations. Criteria for determining the period for post-injection site 

care should be performance-based and a function of the site specific 

characteristics of a project such as project size, geologic factors, and 

relative risk of the project. Such criteria are provided in our edits to 

§146.93(b)(3). 

Individual Response: 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 

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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 acknowledges there will be circumstances where it 

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

of endangerment to USDWs. For this reason, the GS rule offers owners or operators flexibility 

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

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

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

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

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

USDWs pursuant to requirements at §146.93(c). 

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

for post-injection site care will be necessary in most cases. The default 50 year post-injection site 

care timeframe represents a reasonable and protective monitoring period based on a review of 

research studies, industry reports, and existing environmental programs, and evaluation of public 

comments. 

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

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

USDWs from endangerment. 

Letter ID: 0190 Comment ID: 24498 Letter Lines: 3218 to 3229 

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

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

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

Comment: Rule Provision: 146.93(b)(2) 

Proposed CCS Group Recommendations: (2) If the owner or operator can request and 

demonstrate to the satisfaction of the Director before 50 years, based on 

monitoring and other site-specific data, that the geologic sequestration project 

no longer poses an endangerment to USDWs, the Director may approve an amendment 

to THAT the post-injection site care and site closure plan SHOULD BE REVISED 

to reduce the frequency of monitoring, THE DIRECTOR SHALL APPROVE THE 

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REDUCTION. 

or may authorize site closure before the end of the 50-year period. 

Basis for CCS Group Comments: See rationale stated above for eliminating 50-year 

period. 

Individual Response: As described above, EPA disagrees that a post-injection site care 

timeframe of 50 years is excessive in most cases or arbitrary, and retains the default 50-year 

post-injection site care timeframe in the final rule. 

Letter ID: 0190 Comment ID: 24499 Letter Lines: 3231 to 3283 

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

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations 

Comment: Rule Provision: 146.93(b)(3) 

Proposed CCS Group Recommendations: (3) Prior to authorization for site closure, 

the owner or operator must DEMONSTRATE TO THE DIRECTOR, BASED ON 

MONITORING, 

OTHER SITE-SPECIFIC DATA, AND MODELING THAT IS REASONABLY CONSISTENT 

WITH SITE 

PERFORMANCE, THAT NO ADDITIONAL MONITORING IS NEEDED TO ASSURE 

THAT THE GEOLOGIC 

SEQUESTRATION PROJECT DOES NOT AND IS NOT EXPECTED TO POSE AN 

ENDANGERMENT TO 

USDWS. THE DIRECTOR SHALL APPROVE CLOSURE IF THE OWNER OR OPERATOR 

DEMONSTRATES, 

BASED ON THE CURRENT UNDERSTANDING OF THE SITE, INCLUDING 

MONITORING DATA AND/OR 

MODELING, ALL OF THE FOLLOWING: (I) THE ESTIMATED MAGNITUDE AND 

EXTENT OF THE 

PROJECT FOOTPRINT (CO2 PLUME AND THE AREA OF ELEVATED PRESSURE) ; (II) 

THE 

ESTIMATED LOCATION OF THE DETECTABLE CO2 PLUME; (III) THAT THERE IS NO 

SIGNIFICANT LEAKAGE OF EITHER CO2 OR DISPLACED FORMATION FLUIDS THAT 

IS 

ENDANGERING USDWS; (IV) THAT THE INJECTED OR DISPLACED FLUIDS ARE NOT 

EXPECTED 

TO MIGRATE IN THE FUTURE IN A MANNER THAT ENCOUNTERS A POTENTIAL 

LEAKAGE PATHWAY 

INTO A USDW; (V) THAT THE INJECTION WELLS AT THE SITE COMPLETED INTO 

OR THROUGH 

THE INJECTION ZONE OR CONFINING ZONE ARE PLUGGED AND ABANDONED IN 

ACCORDANCE 

WITH THESE REQUIREMENTS; AND (VI) ANY REMAINING PROJECT MONITORING 

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WELLS AT THE 

SITE ARE BEING MANAGED BY A PERSON AND IN A MANNER ACCEPTABLE TO 

THE DIRECTOR. 

Basis for CCS Group Comments: We believe there are three problems with the 

closure standard in proposed section 146.93(b). First, the presumption that 

monitoring should continue for 50 years is unnecessary and counterproductive. A 

straight performance standard is preferable to this or any other fixed time 

period because it provides a clearer standard and an incentive to maximize the 

understanding of site and project performance and as such is more protective of 

USDWs. Second, the proposal requires a showing that the CO2 plume has 

"stabilized", which is undefined. Cessation of plume movement is not necessarily 

essential to show that a project poses no threat of endangerment to USDWs-plumes 

that are still moving may, nonetheless, remain contained. Instead, it is more 

protective to show that the plume is not expected to encounter a leakage 

pathway. Third, the required showing that "no additional monitoring is needed" 

does not provide guidance regarding how an operator is to show that no 

additional monitoring is needed. The proposal below provides specific guidance 

on what the operator must show. 

We recommend the standard in the proposed alternative language for section 

146.93(b) below because it sets forth detailed criteria, all of which must be 

satisfied, to demonstrate that the site does not pose an endangerment to USDWs. 

The specific criteria listed in our proposal will serve to provide the Director 

with the requisite information to make the appropriate determination. The 

advantage of this approach is that it establishes clear criteria that an 

operator must demonstrate before obtaining site closure based upon particular 

site characteristics and is, therefore, reasonably applicable to any storage 

site as opposed to a standard based upon a fixed-duration. Furthermore, it is 

more stringent than a purely discretionary approach because it establishes 

specific criteria that must be shown before site closure may be granted. We 

believe this language, which is an extension of work done by the World Resources 

Institute and the Ground Water Protection Council, avoids the noted shortcomings 

and provides stronger protection for USDWs. 

This is the same recommendation as presented by the multi-stakeholder group, in 

which the Carbon Sequestration Council participated. 

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

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

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

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

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

the monitoring timeframe is appropriate. 

The post-injection site care requirements in the final GS rule incorporate a combination of a 

fixed timeframe and a performance standard approach. The final GS rule offer owners or 

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

discretion to shorten or lengthen the PISC timeframe during the post-injection period based on 

site-specific data, pursuant to requirements at §146.93(b); or (2) affording the Director discretion 

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

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

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

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

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

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

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

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

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

impacts. 

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

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

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

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

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

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

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

Letter ID: 0190 Comment ID: 24500 Letter Lines: 3285 to 3292 

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

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

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment: Rule Provision: 146.93(b)(4) 

Proposed CCS Group Recommendations: (4) If such a demonstration cannot be made 

(i.e., if the carbon dioxide plume and pressure front have not stabilized) after 

the 50-year period, the owner or operator must submit to the Director a plan to 

continue post-injection site care. 

Basis for CCS Group Comments: No longer necessary with 50-year period deletion. 

Individual Response: As described above, EPA believes 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. 

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Letter ID: 0190 Comment ID: 24501 Letter Lines: 3294 to 3298 

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

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment: Rule Provision: 146.93(c) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment and the final rule retains the text as 

proposed. 

Letter ID: 0190 Comment ID: 24502 Letter Lines: 3300 to 3304 

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

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

Comment: Rule Provision: 146.93(d) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the commenter’s support; the final rule retains this 

provision. 

Letter ID: 0190 Comment ID: 24503 Letter Lines: 3306 to 3343 

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

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93) 

Comment: Rule Provision: 146.93(e) 

Proposed CCS Group Recommendations: (e) Once the Director has 

authorizeSd site closure, the owner or operator must submit a site closure 

report within 90 days that must thereafter be retained at a location 

designated by the Director. AFTER COMPLETION OF ALL CLOSURE OPERATIONS. The 

report must include: 

(1) Documentation of appropriate injection and monitoring well plugging as 

specified in §146.92 and paragraph (c) of this section. The owner or operator 

154
must provide a copy of a survey plat which has been submitted to the local 

zoning authority designated by the Director. The plat must indicate the location 

of the injection well(S) relative to permanently surveyed benchmarks. The owner 

or operator must also submit a copy of the plat to the Regional Administrator of 

the appropriate EPA Regional Office; 

Basis for CCS Group Comments: Once the site closure report is submitted to the 

Director, the operator cease to bear responsibility for any further record 

retention. At this point, EPA becomes the steward of information for the 

project. 

Rule Provision: 146.93(e)(2) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Rule Provision: 146.93(f) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Rule Provision: 146.93(g) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA disagrees that the owner or operator should not be responsible for 

record retention such as site closure reports. EPA believes that the requirements that the owner or 

operator retain for ten years following site closure, records collected during the post-injection 

site care period at §146.93(f) and §146.93(h) are appropriate for the post-injection and site 

closure period to ensure that data are available to support non-endangerment demonstrations and 

to address any concerns that may arise following site closure. This data will also support EPA's 

review of project data as part of the adaptive rulemaking approach. 

The GS regulation at §146.93(g) requires the owner or operator to record a notation on the deed 

to the facility property or other similar document examined during a title search that the land has 

been used to sequester CO2 at the time of site closure. 

EPA acknowledges the commenter’s support of the other parts; the final rule retains these 

provisions. 

Letter ID: 0190 Comment ID: 24504 Letter Lines: 3345 to 3359 

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

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

Comment: Rule Provision: 146.94(a) 

Proposed CCS Group Recommendations: (a) As part of the permit application, the 

owner or operator must provide the Director with an emergency A RISK-BASED 

remedial response plan that describes actions to be taken to address movement of 

the injection or formation fluids that may cause an endangerment to a USDW 

during construction, operation, closure and post-closure periods. 

Basis for CCS Group Comments: Any response plan should be based on a risk 

assessment and risk management approach that accounts not only for potential 

causes of endangerment, but probabilities and potential timing of occurrence as 

determined on a site-specific basis. As EPA has recognized, "The SDWA does not 

provide authority to develop regulations for all areas related to GS." 73 Fed. 

Reg. at 43495. Accordingly, the nature and scope of any such plans will 

necessarily be limited to the extent of that authority. 

Individual Response: EPA agrees that emergency and remedial response plans should be riskbased, however, EPA did not make the requested change. The Agency believes that the 

requirement to develop a site-specific emergency and remedial response plan that is informed by 

required site characterization data collected under per §146.82, modeling for AoR evaluations 

and reevaluations, per §146.84, and monitoring data, per §146.90, will appropriately address 

commenter concerns regarding the need for a risk-based emergency and remedial response plan. 

Letter ID: 0190 Comment ID: 24505 Letter Lines: 3361 to 3396 

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

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

Comment: Rule Provision: 146.94(b) 

Proposed CCS Group Recommendations: (b) If the owner or operator obtains 

evidence that the injected carbon dioxide stream, DISPLACED FORMATION FLUIDS OR 

and associated pressure front may cause an endangerment to ENDANGERS a 

USDW, the owner or operator must: 

(1) Immediately Cease injection IN A PRUDENT MANNER CONSIDERING 

CIRCUMSTANCES. 

(2) Take all steps reasonably necessary to identify and characterize THE 

ENDANGERMENT POSED; 

(3) Notify the Director or the designated representative within 24 hours OF 

BECOMING AWARE OF THE ENDANGERMENT; and 

156
Basis for CCS Group Comments: Technical clarifications. 

Under some circumstances, an immediate cessation of injection could have adverse 

impacts on other aspects of the operation. 

Rule Provision: 146.94(c) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Rule Provision: 146.94(d) 

Proposed CCS Group Recommendations: (d) The owner or operator must notify the 

Director prior to conducting any well workover IN RESPONSE TO ANY CASE OF 

ENDANGERMENT. 

Basis for CCS Group Comments: In critical situations, time spent obtaining 

approval could adversely affect the ability to conduct operations or increase 

the level of endangerment. 

Individual Response: After consideration of comments, EPA has finalized the rule language in 

§146.94(b) as proposed. In the introductory section of §146.94(b), EPA clarifies that the pressure 

front, as defined in §146.81, is a zone where the pressure differential is sufficient to cause the 

movement of injected fluids or formation fluids into a USDW. Therefore, displaced formation 

fluids are implicitly included in the requirements for §146.94. EPA also clarifies that owners or 

operators must take action when the CO2 stream or pressure front may cause endangerment. In 

order to prevent the endangerment of USDWs, as required under §1421 of the SDWA, EPA 

expects the owner or operator to act preemptively and not wait until endangerment has occurred. 

This language is consistent with existing UIC requirements for other well classes and EPA’s 

authority under the SDWA. 

EPA clarifies that the Agency expects that owners or operators should take care not to damage 

the well when ceasing injection under §146.94(b)(1). At §146.94(b)(2), EPA is maintaining the 

requirement to “characterize the release.” In order to prevent the endangerment of USDWs, as 

required under §1421 of the SDWA, EPA expects the owner or operator to act preemptively and 

not wait until endangerment has occurred. This language is consistent with existing UIC 

requirements for other well classes and EPA’s authority under the SDWA. 

EPA clarifies that the 24-hour notification required under §146.94(b)(3) begins when the owner 

or operator obtains evidence of possible endangerment. EPA believes the rule language is clear 

on this requirement. 

Since proposal, EPA has modified the final regulatory language at §146.94(d) to clarify what 

constitutes a workover to address a well failure (which invokes remedial actions) and what 

157
constitutes a maintenance-type workover. For maintenance-type workovers (i.e., those that are 

scheduled in advance), the owner or operator must notify and gain approval from the Director 

prior to beginning the workover. In the final GS regulation, EPA has moved this requirement to 

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

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

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

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

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

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

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

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

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

required under the SDWA. 

Letter ID: 0190 Comment ID: 24506 Letter Lines: 3408 to 3418 

Comment Code: 5610 2.11.1 Allowing partial primacy for Class VI wells (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43497 

EPA Preamble Question: 1. EPA seeks comment on any aspects of the ongoing State 

efforts to regulate the GS of CO2 and how these efforts might be used to better 

inform a final Federal rulemaking. EPA Notice 43497. 

CSC Response: Use state approaches as examples to support recommendations where 

appropriate. As EPA moves toward finalizing this rule, EPA should monitor state 

rulemaking to assess the extent to which its rule needs to afford state 

Director’s the flexibility to account for regional differences. We also support 

the implementation of separate primacy for Class VI separately from other 

classes of wells. 

Individual Response: EPA agrees with commenters that states should be allowed to obtain 

primacy for Class VI wells independently of other well classes, and will allow independent 

primacy for Class VI wells under §145.1(i) of the final GS rule. Given the potential for CCS 

(encompassing capture, transportation, and geologic sequestration) to be an important part of a 

national priority to address climate change, EPA believes that providing states the flexibility to 

obtain primacy for Class VI wells independently of other well classes can help foster effective 

management of CCS. EPA believes that allowing independent Class VI primacy may encourage 

states to take responsibility for implementation of Class VI regulations and provide for a more 

comprehensive approach to managing CCS projects by promoting the integration of GS activities 

under SDWA into a broader framework for managing CCS. Furthermore, GS operations involve 

ancillary activities (e.g., pipeline operations, pore space ownership, land use rights, and surface 

access) for which states can call upon other authorities that exist at the state level (but outside 

UIC authority) to provide a more comprehensive CCS management approach. 

158
The Agency believes that it is important for states to use their unique efficiencies to promote 

adoption of this burgeoning and important technology, while assuring that USDWs are protected 

from endangerment through the UIC regulatory framework. EPA believes that, due to the 

importance of implementing an effective, comprehensive, and seamless CCS program, States 

should be provided the flexibility to obtain primacy for Class VI only. 

EPA also believes that allowing states to apply only for Class VI primacy will shorten the 

primacy approval process for states. EPA's willingness to accept independent primacy 

applications for Class VI wells represents a shift in its longstanding policy of discouraging 

"partial primacy." It is very important to note that this shift in policy allowing for Class VI 

primacy does not apply to any other well Class under Section 1422. EPA will continue to 

discourage applications for partial primacy for all other well types under Section 1422. 

EPA clarifies that states should be able to obtain primacy for Class VI wells independent of other 

well classes provided they develop regulations that are at least as stringent as the minimum 

Federal requirements (e.g., permitting, inspection, operation, monitoring, and recordkeeping 

requirements) provided in the final GS rule. EPA believes that existing programs can adapt their 

expertise to the new requirements for Class VI wells and will be able to develop a primacy 

application for Class VI wells under section 1422 of SDWA and ensure that their GS programs 

integrate into national climate change priorities and protect USDWs from endangerment. 

Throughout the process of this rulemaking EPA has been keeping track of individual state 

legislative regulatory approaches. The Agency recognizes that some states have already begun 

legislative efforts that are wider in scope than the Federal GS rule and believes that allowing 

Class VI primacy (independent of other well classes) may encourage states to take responsibility 

for implementation of a more comprehensive approach to managing CCS projects (e.g., capture, 

transportation, and geologic sequestration). EPA considered those legislative approaches that are 

within the scope of the SDWA while finalizing this rulemaking. 

Letter ID: 0190 Comment ID: 24507 Letter Lines: 3420 to 3437 

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: Rule Provisions or Federal Register Cite: 73 FR 43502 

EPA Preamble Question: 2. Injection of CO2 for the purposes of enhanced oil and 

gas recovery (EOR/EGR), as long as any production is occurring, will continue to 

be permitted under the Class II program. EPA seeks comment on the merits of this 

approach since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted. EPA Notice 43502. 

CSC Response: EOR needs to be maintained under the current Class II program and 

any storage that occurs under EOR should continue to be handled under the Class 

II program. CSC supports the language developed by the multi-stakeholder 

159
discussion (MSD) group that would make this more explicit. 

We also support the absence of an economic test for oil and gas reservoir 

"depletion." The MSD group has developed language for differentiating between 

wells in oil and gas reservoirs that should be permitted under the current Class 

II program requirements and those that should be permitted under other 

provisions (preferably as Class II wells subject to enhanced requirements). 

Individual Response: EPA is developing guidance on transitioning permits from Class II to 

Class VI. The guidance will assist Directors in determining whether an injection project should 

be transitioned from Class II, where the primary purpose is oil and gas production, to Class VI, 

where the primary purpose is long-term storage of large volumes of CO2. The guidance 

describes recommended methods the Director may use to evaluate changes in risk to USDWs 

from projects, and how the Director may determine whether a project should be regulated within 

the Class II or Class VI UIC program. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. For more information, please 

see the discussion on transition of Class II wells in the preamble to the final GS rule. 

Letter ID: 0190 Comment ID: 24508 Letter Lines: 3439 to 3468 

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

Comment: Rule Provisions or Federal Register Cite: 146.81(c) 

EPA Preamble Question: 3. EPA seeks comment on the approach to grandfather 

construction requirements at the Director’s discretion for existing Class I, 

Class II, and Class V wells seeking to convert to Class VI wells, and whether 

additional construction requirements would be necessary to prevent endangerment 

to USDWs from the GS of CO2. EPA Notice 43502. 

CSC Response: CSC strongly supports a regulatory approach that would facilitate 

the transition of existing wells constructed to Class I, Class II and Class V 

standards to GS wells regulated under provisions of the proposed rule. In all 

cases, such existing wells will have been permitted under conditions sufficient 

to protect USDWs and will have a demonstrated record of performance under their 

existing operations and MIT programs that can be used as a basis for conversion 

to the Class VI program or (in the case of GS wells in depleted oil and gas 

reservoirs) to enhanced Class II requirements. In particular, wells constructed 

to current Class II standards with demonstrated success in CO2 service should be 

eligible for grandfathering with minimal steps such as notification and permit 

modifications to add any additional requirements necessary to address geologic 

containment of injected carbon dioxide streams. Wells with this performance 

record should not require any additional structural requirements to ensure 

protection of USDWs because of their demonstrated success. 

Rule Provisions or Federal Register Cite: 146.81(c) 

EPA Preamble Question: 4. Additionally, EPA seeks comment on how the 

160
grandfathering approach for existing wells may affect compliance with the other 

requirements in its proposal. EPA Notice 43502. 

CSC Response: All components of the existing wells with a proven record of 

performance should be grandfathered unless there are specific USDW endangerment 

concerns identified by the Director. See Comment above. 

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). 

As described above, EPA disagrees that other requirements (e.g., MITs, siting, monitoring, 

operational, and AoR requirements) should also be grandfathered. Following re-permitting, these 

projects must be subject to the operational, MIT, monitoring, reporting, plugging, and postinjection 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: 0190 Comment ID: 24509 Letter Lines: 3470 to 3487 

Comment Code: 4430 2.4.4.3.3 Injection into coal seams above USDWs (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 144.6(f), 146.5, 146.81 

EPA Preamble Question: 5. EPA is proposing to preclude the injection of CO2 for 

long-term storage into coal seams where they are above the lowermost USDW. EPA 

requests comment on this proposed prohibition. EPA Notice 43503. 

CSC Response: CSC opposes this restriction. Qualification of a formation for 

storage should be based on performance-based standards and site-specific 

considerations. Because we recommend allowing GS in formations that may be above 

the lowermost USDW, the rule should clearly provide that GS would only be 

allowed into an injection zone for which Director determines that geologic and 

other conditions exist that will prevent fluid movement that endangers USDWs 

above or below. 

There are significant differences in geology from one area of the country to 

another. Rather than impose an arbitrary limit based on the depth of the 

lowermost USDW or a specific minimum depth restriction, EPA should follow its 

stated objective and use a performance standard that is clearly spelled out and 

can be met with appropriate demonstrations of containment. 

Individual Response: The final GS rule does not categorically preclude or prohibit injection 

into any type of formation, including coal seams. Instead, the requirements are designed to 

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ensure protection of USDWs from endangerment through proper siting, well construction, 

operation, monitoring, and PISC at all sites selected for GS. 

EPA recognizes that some types of formations, such as coal seams and basalts, are typically 

shallow and above the lowermost USDW. EPA expects that most injection wells conducting GS 

in these shallow formations will be permitted as Class VI wells and such wells will be issued 

waivers, provided that their owners or operators can meet all of the requirements for an injection 

depth waiver at §146.95 and demonstrate that such injection can be performed in a manner that 

protects USDWs, as long as appropriate protections are in place. The Class V experimental 

technology well classification, may, in some instances be an appropriate permitting alternative. 

This decision should be informed through a discussion between the injection well owner or 

operator and the Director to determine the purpose and proper design of the well. 

For additional information on the waiver approach and aquifer exemptions for Class VI wells, 

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: 0190 Comment ID: 24510 Letter Lines: 3489 to 3515 

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

USDW 

Comment: Rule Provisions or Federal Register Cite: 144.6(f), 146.5, 146.81 

EPA Preamble Question: 6. The location and proximity of other formations to 

USDWs may preclude their use for GS. EPA seeks comment on prohibiting injection 

into such formations if they are above the lowermost USDW. EPA Notice 43503. 

CSC Response: Restricting injection to formations below the lowermost 

underground source of drinking water or USDW is not necessary for the protection 

of USDWs and would remove a vast number of viable formations from consideration. 

Industry has shown that it can operate CO2 injection wells in an EOR context 

without endangering USDWs that are located below the injection zone. An 

excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

measures that would provide real assurance of formation integrity and require 

operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. 

In conjunction with this recommendation, CSC also recommends that all GS into 

basalts, coal seams, and salt domes be conducted under Class V as experimental 

wells initially and then as commercial scale Class V wells/projects as the 

experimental projects or other factors allow applicants to demonstrate that 

these sites can be suitable for geological sequestration while preventing 

endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain 

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experience in developing suitable permitting requirements for such wells and to 

tailor those requirements until the agencies are ready to adapt the Class VI 

regulations or other requirements as appropriate. 

Individual Response: EPA anticipates that some owners or operators will apply for Class V 

experimental technology permits for injection into formations including shallow basalts, coal 

seams, salt caverns, and shales. These formations may or may not be located above the 

lowermost USDW or between USDWs. To facilitate experimental injection for GS and to 

increase understanding of injection into these formation types, the Agency is amending the Class 

V experimental technology guidance. The guidance will be available on EPA's web site, at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. EPA acknowledges that the 

Class V experimental technology well sub-classification may be appropriate for these projects, 

provided they are experimental in nature. EPA expects that, following the final GS rule, a limited 

number of experimental injection projects testing GS technology will continue. EPA anticipates 

that these projects will be small-scale and involve limited CO2 volumes. However, if these 

projects become larger scale and are no longer experimental, they will need to be permitted as 

Class VI wells. The construction, operation, or maintenance of any non-experimental Class V GS 

well is prohibited, at §144.15. 

Letter ID: 0190 Comment ID: 24511 Letter Lines: 3505 to 3515 

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

Comment: In conjunction with this recommendation, CSC also recommends that all GS into 

basalts, coal seams, and salt domes be conducted under Class V as experimental 

wells initially and then as commercial scale Class V wells/projects as the 

experimental projects or other factors allow applicants to demonstrate that 

these sites can be suitable for geological sequestration while preventing 

endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain 

experience in developing suitable permitting requirements for such wells and to 

tailor those requirements until the agencies are ready to adapt the Class VI 

regulations or other requirements as appropriate. 

Individual Response: EPA expects that, after promulgation of the final rule, a limited number of 

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

technology associated with GS into basalts, coal seams, and salt domes. EPA clarifies that such 

projects are experimental in nature and would be to test new technologies, and that EPA does not 

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

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

Class V experimental technology wells. Such wells should be permitted as Class VI wells. 

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

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

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

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

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

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

Letter ID: 0190 Comment ID: 24512 Letter Lines: 3517 to 3560 

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

Comment: Rule Provisions or Federal Register Cite: 146.81(b), 146.81(d) 

EPA Preamble Question: 7. By defining "carbon dioxide stream" to exclude 

hazardous wastes (146.81(d)), EPA’s rule, if finalized, assures that it would 

apply only to CO2 streams that are not hazardous wastes as defined in 40 CFR 

Part 261. As a result, EPA’s proposed rule would preclude the injection of 

hazardous wastes in Class VI injection wells. EPA seeks comment on this approach 

and other considerations associated with the presence of "impurities" in the CO2 

stream. EPA Notice 43503. 

CSC Response: CSC agrees with the concept that Class VI wells should not be 

injecting hazardous wastes, but there are believed to be few, if any, 

circumstances under which RCRA hazardous waste provisions would apply to CO2 

streams. Current capture technologies under development are not likely to 

produce a CO2 stream that would ever meet the definition of hazardous waste 

under 40 CFR 261. These CO2 capture technologies will yield a relatively pure 

CO2 stream, one that is unlikely to contain sufficient hazardous constituents to 

qualify as hazardous under any circumstances. To begin with, those CO2 streams 

will constitute uncontained gas that is not even a solid waste under RCRA. 

Moreover, the captured supercritical streams will not be susceptible to normal 

RCRA testing protocols because of the physical characteristics of supercritical 

CO2. 

In addition, we are proposing some modifications to EPA’s definition of CO2 

stream in the rule. The modifications reflect the fact that the source of CO2 

should not be a factor in the context of defining the CO2 stream. The rule 

applies to the injection of CO2 and should not address the origins of the 

materials since that is beyond the scope of this regulation. The original text 

would have precluded injection of CO2 from some sources. The question of how CO2 

should be accounted for, and from what sources, in a GHG management and 

accounting system is beyond the scope of this regulation. 

More to the issue of "impurities", CSC objects to any mandated purity standards 

for CO2. The inclusion of impurities in stored CO2 should not be arbitrarily 

prohibited; however, it is recognized that the presence of those impurities at 

sufficient concentrations may trigger the applicability of other statutory 

limits or requirements. Determining the type and levels of impurities in the CO2 

stream is " absent a compelling public or environmental health risk " best left 

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to contractual negotiations between parties in a CCS value chain as opposed to 

an arbitrary regulatory determination. The contracting parties are best able to 

evaluate the types of impurities, their compatibility with the reservoir and 

equipment, and determine the acceptable levels of those impurities in the stored 

CO2. If there were ever any overriding public interest in limiting either the 

type or level of contaminants, principles of cost-effectiveness and riskmanagement should guide the decision making process. 

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

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

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

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

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

composition, plant operating conditions, and pollution removal technologies. 

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

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

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

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

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

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

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

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

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

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

minerals. 

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

waste under 40 CFR part 261, injection of a CO2 stream that is determined to be a hazardous 

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

Letter ID: 0190 Comment ID: 24513 Letter Lines: 3562 to 3594 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43504 

EPA Preamble Question: 8. Class VI requirements and permits will need to be 

carefully structured to ensure that they do not "authorize" inappropriate 

hazardous releases. This would include clarifying if there are potential 

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

requests comment on particular situations where this might occur. EPA notice 

43504. 

CSC Response: Well chosen sites should prevent these conditions from occurring. 

At the same time, permit writers should not write permits so restrictive as to 

make the undertaking of a GS project untenable. EPA should remember that CERCLA 

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liability will not only impact owners and operators of GS projects, but also 

hundreds, thousands, and even more numerous pore space owners. EPA should 

consider the threat of subjecting these pore space owners to CERCLA liability. 

Their property interests in the CO2 GS project injection zones could subject 

them to strict, joint, and several liability under CERCLA pursuant to whatever 

liability theories might be developed by future litigants seeking compensation 

for response and remediation costs incurred in the cleanup of releases from 

geologic sequestration injection zones. EPA should recognize the significant 

chilling effect CERCLA liability concerns will have on GS projects, and seize 

the opportunity in this rulemaking to alleviate any CERCLA liability concerns to 

the greatest extent possible. 

Rule Provisions or Federal Register Cite: 73 FR 43504 

EPA Preamble Question: 9. EPA also requests comment on other considerations 

associated with the presence of impurities in the CO2 stream related to CERCLA. 

EPA Notice 43504. 

CSC Response: CSC is concerned that potential CERCLA liabilities will have the 

potential to chill enthusiasm for undertaking GS projects. EPA needs to respond 

clearly and positively to this concern by developing appropriate language in the 

regulations and permits to provide the clarity and assurance needed to promote 

continued research and development for GS projects. 

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

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

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

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

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

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

from the well which are outside the scope of the Class VI permit. Furthermore, EPA is 

promulgating the GS rule under the authority of the SDWA. To the extent the commenter is 

seeking interpretations of CERCLA and its related provisions, such as the definition of a 

federally permitted release, such interpretations are beyond the scope of this rulemaking. 

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

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

USDWs from endangerment. 

Letter ID: 0190 Comment ID: 24514 Letter Lines: 3596 to 3616 

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

(seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43506 

EPA Preamble Question: 10. EPA’s proposal would provide the Director the 

discretion to require the owner or operator to identify and characterize 

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

confining zone that could further impede vertical fluid movement and allow for 

pressure dissipation. EPA says that these layers could provide additional sites 

for monitoring, mitigation, and remediation. EPA’s proposal would not require 

that these additional zones be identified for all GS sites because their absence 

does not necessarily indicate inappropriateness of a GS site. However, if such 

zones are present, information about their characteristics can provide inputs 

for predictive models, identify appropriate monitoring locations, and improve 

public confidence in and acceptance of a proposed GS site. EPA specifically 

seeks comment on the merits of requiring the identification of these additional 

zones. EPA Notice 43506. 

CSC Response: Secondary containment should not be mandatory. There are many 

areas where a single confining zone can be shown to be highly protective of 

USDWs. Adequacy of containment must be demonstrated on a site-specific basis. By 

definition, an additional confining or containment zone beyond is not necessary 

to prevent endangerment of USDWs, and would serve only to prevent the use of 

otherwise-appropriate GS reservoirs. 

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

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

confining zones are not required for all GS sites. 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: 0190 Comment ID: 24515 Letter Lines: 3618 to 3633 

Comment Code: 3330 2.2.1.3 Applicability /adequacy of computational models (seeking 

comment) 

Comment: Rule Provisions or Federal Register Cite: 146.82(c), 146.84, 146.90(d)(2) 

EPA Preamble Question: 11. EPA proposes that the owners or operators of GS wells 

be required to delineate the AoR for CO2 GS sites using computational fluid flow 

models designed for the specific site conditions and injection regime. EPA seeks 

comment on the use of modeling for AoR delineation. EPA Notice 43506. 

CSC Response: Modeling is well developed technology that can readily simulate 

complex behavior of injected CO2. It should be one of the techniques used to 

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delineate the AoR. 

The oil and gas industry has a great deal of experience that can be generally 

applied in the delineation of the AoR. 

The most complex model is not always necessary to adequately delineate the AoR. 

Some CO2 EOR projects have successfully operated for decades using only 

production data and pressure mapping, which has in effect defined AoR. 

Individual Response: EPA agrees that the oil and gas industry has contributed to the state of 

modeling science, and anticipates that some industry-developed modeling products will be 

acceptable for models in the AoR for GS sites, as long as GS well operators clearly disclose, to 

the Director's satisfaction, the code assumptions, relevant equations, and scientific basis. 

EPA clarifies that the model inputs must include actual geologic information, data collected 

during the site characterization process (e.g., information about artificial penetrations), and 

anticipated operating parameters (e.g., injection rates) submitted with the permit application 

under §146.82. Models will be revised and recalibrated during subsequent AoR reevaluations, 

which must account for all available monitoring and operational data, as required at §146.84(e). 

EPA encourages and expects owners or operators to use the most appropriate multiphase 

computational models available to determine the AoR. However, EPA does not believe that the 

most "complex" model will, in all cases, be the best available AoR delineation model. The 

requirements at §146.84(c)(1) are designed to allow the owner or operator to choose, in 

consultation with the Director, the modeling platform that is most appropriate for a particular GS 

project. 

EPA anticipates that modeling technology will continue to improve, and encourages and expects 

owners or operators to use the best available multiphase computational models to determine the 

AoR. Reliance on improved models will likely increase the accuracy and quality of the AoR 

characterization, resulting in increased protection of USDWs from endangerment. 

Letter ID: 0190 Comment ID: 24516 Letter Lines: 3635 to 3649 

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

Comment: Rule Provisions or Federal Register Cite: 146.84 

EPA Preamble Question: 12. In some cases, owners or operators may choose to use 

proprietary models (i.e., not available for free to the general public). EPA 

says it is aware that the use of proprietary codes may prevent full evaluation 

of model results (e.g., NRC, 2007). Several popular codes in the petroleumreservoir engineering discipline are proprietary and owners or operators of 

particular sites may prefer to use these codes as they have previous experience 

with them, and they have been used in peer-reviewed studies to model CO2 

sequestration. When using a proprietary model, owners or operators should 

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clearly disclose the code assumptions, relevant equations, and scientific basis. 

EPA seeks comment on allowing the use of proprietary models for GS sites. EPA 

Notice 43507. 

CSC Response: Use of proprietary models should be allowed. EPA’s Confidential 

Business Information requirements should apply to any proprietary model used. 

Individual Response: EPA agrees that some of the available proprietary models may meet the 

needs for calculating the AoRs of GS sites. EPA will allow their use in meeting the requirements 

for the GS regulation, but clarifies that GS well operators using proprietary models are required 

to disclose, to the Director's satisfaction, the code assumptions, relevant equations, and scientific 

basis. EPA acknowledges that several proprietary models have been used by petroleum-reservoir 

engineering professionals as well as in peer-reviewed studies to model CO2 sequestration. EPA 

adds that its Confidential Business Information requirements at 40 CFR 144.5 will apply to the 

use of proprietary models. Information including model assumptions and equations are used by 

the Director to inform his/her decision to issue the permit and ensure that the requirements are 

met and the GS well will not endanger USDWs. EPA adds that its Confidential Business 

Information requirements at 40 CFR 144.5 will apply to the use of proprietary models. 

Letter ID: 0190 Comment ID: 24517 Letter Lines: 3651 to 3657 

Comment Code: 3330 2.2.1.3 Applicability /adequacy of computational models (seeking 

comment) 

Comment: Rule Provisions or Federal Register Cite: 146.84 

EPA Preamble Question: 13. EPA seeks comment on the applicability of 

computational fluid flow models for delineating the AoR of GS sites. EPA Notice 

43507. 

CSC Response: Computational fluid flow models can inform the delineation of the 

AoR. (See also Comment on Question 11 above.) 

Individual Response: EPA encourages and expects owners or operators to use the most 

appropriate multiphase computational models available to determine the AoR. The requirements 

at §146.84(c)(1) are designed to allow the owner or operator to choose, in consultation with the 

Director, the modeling platform that is most appropriate for a particular GS project. EPA adds 

that its Confidential Business Information requirements at 40 CFR 144.5 will apply to the use of 

proprietary models. 

EPA anticipates that modeling technology will continue to improve, and encourages and expects 

owners or operators to use the best available multiphase computational models to determine the 

AoR. Reliance on improved models will likely increase the accuracy and quality of the AoR 

characterization, resulting in increased protection of USDWs from endangerment. 

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Letter ID: 0190 Comment ID: 24518 Letter Lines: 3659 to 3668 

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

Comment: Rule Provisions or Federal Register Cite: 146.84 

EPA Preamble Question: 14. 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 43507. 

CSC Response: Rather than a fixed time period, CSC recommends following a 

performance based approach that would require reevaluation of the AOR as, but 

only as, it is necessary, as determined by consideration of whether there are 

significant unexpected changes in injection parameters or monitoring results. 

Individual Response: EPA agrees that site-specific factors should be considered in the 

reevaluation schedule, and notes that the AoR and corrective action plan must specify the sitespecific monitoring and operational conditions that warrant reevaluation, as specified in 

§146.84(b)(2)(ii). In addition, the Director has discretion to require more frequent AoR 

reevaluation if he or she has reason to believe, based on site-specific information, that a five-year 

reevaluation schedule is not sufficiently protective of USDWs. However, EPA believes that 

setting a minimum reevaluation frequency is appropriate. In the final rule, the Agency changed 

the minimum frequency for the AoR reevaluation at §146.84(e) from ten years to at least every 

five years in the final GS rule. EPA believes that this revised frequency addresses commenters' 

concerns 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. 

In addition, the Director has discretion to require more frequent AoR reevaluation if he or she 

has reason to believe, based on site-specific information, that a five-year reevaluation schedule is 

not sufficiently protective of USDWs. 

Letter ID: 0190 Comment ID: 24519 Letter Lines: 3670 to 3684 

Comment Code: 3630 2.2.4.1 Comments in favor of allowing phased corrective action 

Comment: Rule Provisions or Federal Register Cite: 146.84(f) 

EPA Preamble Question: 15. EPA proposes to allow a phased approach to corrective 

action but says this may not be appropriate in all situations; therefore EPA is 

proposing that the Director have the discretion to decide to allow this 

approach, based on the understanding of relevant geologic and site conditions. 

EPA invites public comment on the merits and frequency of reevaluation of the 

AoR as well as the phased corrective action approach for GS wells. EPA Notice 

43508. 

CSC Response: CSC supports the EPA proposal. The phased approach allows the 

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sound economic execution of the project over time without endangering USDWs. 

This approach prevents an operator from the unnecessary expense of remediating 

wells in an area that ultimately may not be affected by the storage project. 

Frequency of reevaluation should be based on site performance as noted in the 

prior comment. 

Individual Response: EPA acknowledges the commenter’s support of phased corrective action 

and agrees that phased corrective action may provide many benefits to a project including, but 

not limited to, spreading the burden of cost, avoiding delays in project start-up, allowing for use 

of future, improved corrective action techniques and addressing unanticipated changes in the 

movement of the CO2 plume or pressure front. EPA believes that the phased corrective action 

approach is appropriate for GS projects, and retained it at §146.84(b)(2)(iv) in the final GS 

regulation. 

Regarding the comment that some wells identified in the original AoR ultimately may not be 

affected by the storage project, EPA clarifies that, if monitoring or modeling data indicate a 

change in the AoR, the owner or operator would need to review and amend the AoR and 

corrective action plan and follow the amended plan. 

Regarding the comment that AoR reevaluation frequency should be based on site performance, 

as described above, EPA believes that periodic AoR reevaluation at a set frequency of at least 

every five years is necessary to ensure protection of USDWs from endangerment and address the 

uncertainties inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure 

that a deliberate effort is made to verify, based on monitoring and operational data, that the CO2 

plume is moving within the subsurface as predicted. 

Letter ID: 0190 Comment ID: 24521 Letter Lines: 3686 to 3697 

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 146.86(b) 

EPA Preamble Question: 16. 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 

43509. 

CSC Response: Generally the surface casing is set below the lowest USDW above 

the confining zone, but it should be recognized that this is not appropriate in 

all geologic settings. In some areas USDWs can extend to much greater depths 

than would be appropriate for setting of surface casing. Regulations should 

recognize these situations and allow a surface casing setting depth that may not 

fully cover the USDWs. 

Individual Response: Section 146.86(b)(3) requires that the long-string casing extend to the 

injection zone and be cemented by circulating cement to the surface in one or more stages. It 

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does not, however, specify how cementing would be accomplished, and gives flexibility to the 

owner or operator to propose alternate methods to provide a sufficient amount of cement to meet 

the standard that USDWs are protected from endangerment, subject to the approval of the 

Director. EPA notes that there are many potential ways to meet the requirement in deep wells, 

such as the use of staged cementing. See the discussion of Class VI well construction 

requirements in the preamble to the final GS rule for additional information. Additionally, EPA 

is developing guidance on the construction of Class VI wells. This guidance will be available on 

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

EPA adds that cementing of deep wells has been performed successfully in the past, for example, 

by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of 

these wells, which must meet the same cementing requirements for long-string casing as Class 

VI wells, are up to 12,000 feet deep (EPA, 2001). 

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

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

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

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

EPA 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: 0190 Comment ID: 24523 Letter Lines: 3686 to 3690 ; 3705 to 3706 

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 146.86(b) 

EPA Preamble Question: 16. 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 

43509. 

Regarding packer setting depth, the director should retain discretion for 

allowing variation from this requirement. 

Individual Response: EPA clarifies that the rule allows discretion in some areas when UIC 

Directors evaluate and approve the owners or operators proposed well construction plan. The 

Director will evaluate the appropriateness of the proposed construction based on site-specific 

information about the injection project. EPA believes that the use of tubing and packer in 

accordance with §146.86(c) will offer the best multiple-barrier protection of USDWs from 

endangerment. Additionally, EPA is developing guidance on the construction of Class VI wells. 

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This guidance will be available on EPA’s website at 

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

Letter ID: 0190 Comment ID: 24524 Letter Lines: 3708 to 3720 

Comment Code: 2064 1.5.3.2 Grandfathering construction of Class II wells (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 146.81(c) 

EPA Preamble Question: 17. EPA also seeks comment on how the proposed 

grandfathering provisions for existing wells (construction requirements) may 

affect compliance with the above, proposed construction requirements. EPA Notice 

43509. 

CSC Response: By definition, the construction of previously-permitted wells has 

already been determined to be sufficient for protection of USDWs. Consequently, 

additional construction-related requirements should not be imposed in the 

absence of specific evidence of a construction-related deficiency creating a 

potential for endangerment. Because the act of injection would be the same for 

CO2 EOR and CO2 storage, wells in CO2 service constructed to Class II well 

standards should presumptively be sufficient to protect USDWs. 

Individual Response: As described above, EPA agrees that many Class II 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). Following re-permitting as Class VI wells, these projects must be subject to the 

operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure 

requirements in the final GS rule. See the discussion of EPA's final regulatory approach in the 

preamble to the GS rule for additional detail on these requirements. 

Letter ID: 0190 Comment ID: 24525 Letter Lines: 3722 to 3730 

Comment Code: 3840 2.3.2 Horizontal well drilling techniques (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 146.86 

EPA Preamble Question: 18. EPA seeks comment on the merits of horizontal well 

drilling techniques for GS wells and the applicability of well construction 

requirements discussed in this proposal. EPA Notice 43509. 

CSC Response: Drilling of directional and horizontal wells is an established 

technology that can significantly reduce surface impacts of a GS project and 

improve the injection rate of a well. CO2 injection wells at In Salah, Sleipner, 

and in many Texas locations are horizontal or have horizontal sections. 

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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: 0190 Comment ID: 24526 Letter Lines: 3732 to 3744 

Comment Code: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking 

comment) 

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 146.86, 73 FR 43510 

EPA Preamble Question: 19. EPA seeks comment regarding requirements for 

degradation-resistant well construction materials, such as acid-resistant 

cements and corrosion resistant casing. EPA Notice 43510. 

CSC Response: The well should be looked at as a system such that not each 

individual component needs to be CO2 resistant as long as the entire system 

provides an effective barrier under the subsurface conditions. Industry 

experience with CO2 EOR strongly supports the use of conventional oil field 

tubing, casing, and cements. Industry experience over the past 35 years has led 

to the development of corrosion mitigation measures (e.g. plastic or epoxy lined 

tubing, use of corrosion inhibitors, and proper dehydration of CO2) that provide 

a high degree of protection and mitigate any corrosive effects of injected CO2. 

Individual Response: EPA recognizes that the oil and gas industry has decades of experience 

injecting CO2 for the purpose of enhanced recovery, and that this practice has led to the 

development of many corrosion mitigation measures that would be appropriate for the design of 

Class VI wells. 

EPA believes that the GS rule provides flexibility: it does not specify materials to be used. 

Rather, it provides owners or operators with the flexibility to choose, as long as the materials 

used in Class VI wells are compatible with fluids with which they may come into contact and 

meet or exceed standards developed for such materials by API or ASTM International, or 

comparable standards approved by the Director, as provided at §146.86(b)(1). However, EPA 

clarifies that each individual component of the well system must be described by the owner or 

operator and will be evaluated by the Director and must meet the requirements of the GS rule. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

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

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Letter ID: 0190 Comment ID: 24527 Letter Lines: 3746 to 3755 

Comment Code: 4130 2.4.1.3 Appropriateness of using fracturing for well stimulation (seeking 

comment) 

Comment: Rule Provisions or Federal Register Cite: 146.88(a) 

EPA Preamble Question: 20. EPA is requesting comment on the extent 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 

43511. 

CSC Response: The use of fracturing for stimulation is appropriate and should be 

allowed provided that there is no damage to the confining unit that would result 

in endangerment of USDWs. There are computer simulators to predict fracture 

behavior so the impact on the confining zone can be anticipated. 

Individual Response: EPA agrees that stimulation, such as hydraulic fracturing, should be 

permitted in some situations, and the final rule allows the use of hydraulic fracturing at GS sites 

where approved by the Director. Hydraulic fracturing is one of several stimulation technologies 

available to improve wellbore and formation injectivity. EPA clarifies that fracturing is permitted 

during stimulation, but not during injection. During injection, the injection pressure must not 

exceed 90 percent of the fracture pressure, as specified in §146.88(a). 

All stimulation, including hydraulic fracturing, must be approved by the Director. Owners or 

operators must submit a proposed stimulation program as part of the permit application under 

§146.82(a)(9); the plan must demonstrate that any stimulation activities will not compromise the 

integrity of the confining zone. The Director will evaluate the owner or operator's proposed 

stimulation plan in the context of all information about the site, and the owner or operator must 

perform stimulation only as approved. It is possible that computer simulations may support this 

determination to the Director's satisfaction. EPA clarifies that all data submitted with the permit 

application, including modeling of the AoR, will inform the Director's decision on whether 

hydraulic fracturing is acceptable at a GS site. 

Letter ID: 0190 Comment ID: 24528 Letter Lines: 3757 to 3764 

Comment Code: 4120 2.4.1.2 Allowing hydraulic fracturing during GS (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43511 

EPA Preamble Question: 21. EPA is also requesting information to better qualify 

the use of fracturing for GS injection in specific geologic settings and rock 

formation lithologies. EPA Notice 43511. 

CSC Response: EPA should allow fracturing for stimulation and should set 

injection pressure limits to preclude initiating, propagating, or opening 

avenues of release through fractures transecting the confining zone. 

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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)). 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). 

EPA clarifies that the injection pressure may not exceed 90 percent of the fracture pressure of the 

injection zone. The final rule retains this provision at §146.88(a). EPA believes that the 90 

percent requirement, which was suggested by state representatives and permit writers whom 

EPA consulted when writing the regulation, is a satisfactory margin of safety for well operation. 

In addition, to maintain the integrity of the confining zone, the final rule requires that, except 

during stimulation, the injection pressure not exceed 90 percent of the fracture pressure of the 

injection zone. 

Letter ID: 0190 Comment ID: 24529 Letter Lines: 3766 to 3785 

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 146.88(e) 

EPA Preamble Question: 22. EPA seeks comment on the merits of requiring downhole shut-off valves in GS wells. EPA Notice 43511. 

CSC Response: Over-pressure protection is best achieved by ensuring 

compatibility of the casing/tubing material design strength with the surface 

injection (compression) system. Down-hole shut-in devices are not appropriate 

for this application. These devices are installed in the tubing string and are 

typically near the surface of the well. They are used in off-shore applications 

where they are intended to seal the tubing at or near the ocean floor in the 

event that the tubing is severed above that point. These devices were not 

designed for use deep underground and would provide little if any protection to 

USDWs. It is not practicable to install these devices deep underground (e.g. 

shortly above the packer). Additionally these devices would create a restriction 

on running other tools like logging tools in the well and therefore could limit 

an operator’s ability to do required monitoring and diagnostic work. Lastly, 

these devices require periodic testing and maintenance which could require 

either pulling the device by wireline or by pulling the entire tubing string 

depending on the type of device installed. Either of these activities would be 

disruptive and costly to the overall project operations. 

Individual Response: As described above, EPA will not require automatic down-hole shut-off 

devices for onshore Class VI wells since it is not necessary in all cases to ensure protection of 

USDWs from endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or 

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operators of onshore Class VI wells install automatic surface shut-off devices. The rule affords 

Director's discretion to mandate automatic down-hole shut-off devices in onshore situations that 

may warrant their use. The rule requires, at §146.88(e)(3), that owners or operators of offshore 

wells within State territorial waters install automatic down-hole shut-off systems. 

Letter ID: 0190 Comment ID: 24530 Letter Lines: 3787 to 3805 

Comment Code: 4410 2.4.4.3.1 Comments in favor of allowing injection above/between 

USDWs in certain circumstances 

Comment: Rule Provisions or Federal Register Cite: 144.6(f), 146.5, 146.81 

EPA Preamble Question: 23. EPA is aware that the proposal to limit CO2 injection 

to reservoirs below the lowermost USDW may preclude injection into certain 

geologic formations currently under consideration for GS. As a result, the 

Agency is considering and requesting comment on alternative approaches that 

would allow injection between and/or above the lowermost USDW, thus potentially 

allowing more areas to be available for GS while preventing USDW endangerment. 

EPA Notice 43512. 

CSC Response: Injection above the lowest USDW should be allowed as long as the 

operator can demonstrate confinement above and below the injection formation. 

Retaining the proposed restriction would remove a significant number of viable 

formations from consideration. It has been shown that CO2 injection wells can be 

operated in an EOR context without endangering USDWs that are located below the 

injection zone. An excellent example is the Salt Creek EOR project in Wyoming, 

which has a USDW below the injection zone. Moreover, under the proposed rule, 

there are other measures that would provide real assurance of formation 

integrity and require operators to demonstrate that their project will not 

endanger USDWs, making the lowermost USDW restriction unnecessary. 

Individual Response: As described above, EPA acknowledges that there are limited 

circumstances where injection above the lowermost USDW can be performed in a manner that 

protects USDWs from endangerment, as long as appropriate protections are in place. The final 

GS rule at §146.95 establishes a process by which owners or operators can seek a waiver of the 

Class VI injection depth requirements for injection into non-USDW formations above and/or 

between USDWs. 

Letter ID: 0190 Comment ID: 24531 Letter Lines: 3807 to 3818 

Comment Code: 4410 2.4.4.3.1 Comments in favor of allowing injection above/between 

USDWs in certain circumstances 

Comment: Rule Provisions or Federal Register Cite: 144.6(f), 146.5, 146.81 

EPA Preamble Question: 24. EPA is soliciting comment on whether CO2 injection 

should be allowed into an injection zone above the lowermost USDW, when the 

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Director determines that geologic conditions (e.g., thousands of feet of 

intervening formations between the injection zone and the overlying and/or 

underlying USDWs) exist that will prevent fluid movement into adjacent USDWs. 

EPA Notice 43512. 

CSC Response: See response to Question 23. CO2 injection zones should be 

selected based upon site specific evaluation of performance based criteria. 

"Thousands of feet of intervening formations" should not be necessary as long as 

it can be demonstrated that USDWs will be protected. 

Individual Response: As described above, EPA acknowledges that there are limited 

circumstances where injection above the lowermost USDW can be performed in a manner that 

protects USDWs from endangerment, as long as appropriate protections are in place. The final 

GS rule at §146.95 establishes a process by which owners or operators can seek a waiver of the 

Class VI injection depth requirements for injection into non-USDW formations above and/or 

between USDWs. 

Letter ID: 0190 Comment ID: 24532 Letter Lines: 3820 to 3838 

Comment Code: 4460 2.4.4.4.1 Comments in favor of allowing aquifer exemptions in certain 

circumstances 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43512 

EPA Preamble Question: 25. EPA is also requesting comments on whether aquifer 

exemptions should be allowed for the purpose of Class VI injection, and under 

what conditions should such aquifer exemptions be approved. EPA Notice 43512. 

CSC Response: At this time, we do not recommend any specific need for new 

aquifer exemption criteria created because the existing criteria are perceived 

to be sufficient to allow aquifer exemptions as needed for GS. Even without 

changes, the aquifer exemption requirements in the UIC program would allow 

operators to obtain appropriate exemptions for GS operations. In addition, there 

should be no requirement that sequestration be below the lowermost USDW. 

Unfortunately - as the preamble to the proposed rule notes - the aquifer 

exemption process has effectively been disabled because EPA has sometimes 

refused to consider aquifer exemption requests for non-injection formations. 73 

Fed. Reg. at 43512. Rather than preventing underground injection that "endangers 

drinking water sources" as the statute requires, this approach arbitrarily 

prevents injection that does not endanger any drinking water sources. This 

approach should be abandoned; instead, the aquifer exemption rules should be 

applied as written. 

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

exemptions for GS may be warranted. The final rule allows for the expansion of the areal extent 

of existing aquifer exemptions for Class II EOR/EGR wells transitioning to Class VI injection 

for GS pursuant to requirements at §§146.4 and 144.7(d). Class VI owners or operators granted 

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expansions of existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of 

the tailored requirements for GS wells in the final GS rule. 

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; 

that is, aquifer exemptions will only be granted for projects that are transitioning from Class II 

EOR/EGR wells to Class VI. 

EPA clarifies that all decisions regarding expansion of existing aquifer exemptions will be at the 

Director's discretion and based on site-specific information. If an owner or operator applies for a 

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located 

above and/or between USDWs, the permit applicant must also apply for a waiver of the injection 

depth requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and 

below the injection zone are protected from endangerment. 

For additional information on aquifer exemptions for Class VI wells, 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: 0190 Comment ID: 24533 Letter Lines: 3840 to 3851 

Comment Code: 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43512 

EPA Preamble Question: 26. EPA seeks comment on whether the Agency should set a 

minimum injection depth requirement for CO2 GS, rather than require that such 

injection take place below the lowermost USDW. EPA Notice 43512. 

CSC Response: There should be no minimum depth for injection of CO2. The primary 

consideration should be protection of USDWs. A requirement for a minimum depth 

suggests an intention by EPA to require injection of CO2 in a supercritical 

phase. Such a requirement is not appropriate since there may be areas where 

injection of CO2 in other phases may be the only option. Again, site-specific 

evaluation and protection of USDWs should be the basis for determining depth of 

injection. 

Individual Response: As described above, EPA agrees that it is not appropriate to set a 

minimum injection depth for GS projects or require that the CO2 be injected in a supercritical 

state. The final GS rule at §146.95 establishes a process by which owners or operators can seek a 

waiver of the Class VI injection depth requirements for injection into non-USDW formations 

above and/or between USDWs. 

Letter ID: 0190 Comment ID: 24534 Letter Lines: 3853 to 3862 

Comment Code: 4490 2.4.5 Use of tracers and potential impact on human health or ecosystems 

(seeking comment) 

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Comment: Rule Provisions or Federal Register Cite: 73 FR 43513-15 

EPA Preamble Question: 27. 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 43513. 

CSC Response: EPA should not mandate the use of tracers. The potential value of 

tracers is uncertain and too limited to justify their use in the injection well 

context. Any use of tracers should be entirely at the option of the operator. 

Individual Response: As described above, 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 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: 0190 Comment ID: 24535 Letter Lines: 3864 to 3879 

Comment Code: 4520 2.5.1 Continuous internal mechanical integrity monitoring (seeking 

comment) 

Comment: Rule Provisions or Federal Register Cite: 146.89(b) 

EPA Preamble Question: 28. EPA’s proposal would require owners or operators of 

Class VI GS projects to monitor internal mechanical integrity of their injection 

wells by continuously monitoring injection pressure, flow rate, and injected 

volumes, as well as the annular pressure and fluid volume to assure that no 

anomalies occur that may indicate an internal leak. EPA requests comment on the 

practicability of this requirement. EPA Notice 43513. 

CSC Response: There is concern regarding what constitutes continuous monitoring. 

Industry agrees that regular monitoring of the parameters identified by EPA is 

appropriate. Our experience with CO2 EOR strongly shows that daily monitoring of 

most of these parameters is adequate (exceptions to this would be on a sitespecific basis). Recording should generally be done on a daily basis and 

reporting on a semi-annual basis. As a guiding principle, the frequency of 

monitoring should be determined by the level of risk posed by the injection 

operation. 

Individual Response: EPA believes that continuous pressure monitoring to demonstrate internal 

mechanical integrity of Class VI wells required at §146.89(b), instead of periodic testing (which 

is required for most other types of deep injection wells), is important given the potential 

corrosive impact of CO2 and impurities on well materials, the potential geomechanical impacts 

to well integrity due to CO2 phase changes, and the temperature and pressure effects associated 

with injecting supercritical CO2. EPA also believes that the technology for continuous 

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monitoring is practicable, available, and is currently in fairly wide use. At least one commenter 

indicated that the technology required for continuous monitoring is currently available and 

should not present an undue cost burden. Continuous annulus monitoring is also conducted at the 

commercial-scaled carbon capture and geologic sequestration operation at the In Salah, Algeria 

natural gas plant where more than 3 million tons of CO2 have been sequestered since 2004. 

Class VI injection wells will be equipped with dedicated computer-based continuous pressure 

monitoring devices (in concert with the shut-off systems required for GS wells), which typically 

take readings several times per second (i.e., more frequently than daily) and record them 

electronically in a computer system. 40 CFR §146.91(a)(2) requires that monthly averages of the 

continuous annulus monitoring be reported on a semiannual basis. 

Letter ID: 0190 Comment ID: 24536 

Comment: Individual Response: 

Letter ID: 0190 Comment ID: 24537 Letter Lines: 3881 to 3890 

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 146,89(c), 146,90(e) 

EPA Preamble Question: 29. EPA seeks comment on the appropriate frequency of 

internal and external MITs for GS injection wells, the appropriate types of 

MITs, and how to optimize MIT methods for GS. EPA Notice 43514. 

CSC Response: Timing for conducting MITs, should be based on risk and 

performance factors. Industry experience with CO2 EOR Class II program requires 

MITs every 5 years. This frequency has proven protective of USDWs. Given the 

similarities between CO2 EOR wells and GS wells, CSC recommends 5-year frequency 

in this case as well. The MIT should test integrity of the long string casing, 

Individual Response: EPA disagrees that a five-year external MIT is appropriate. The final GS 

regulation retains the requirement that owners or operators of Class VI wells must demonstrate 

injection well external mechanical integrity at least once annually under §146.89(c). While EPA 

acknowledges the successful history of the Class II injection program, the Agency believes that 

CO2 injection for GS is substantially different from Class II ER operations in that: 1) the purpose 

of CO2 injection for GS is permanent storage, whereas for ER operations injected CO2 is often 

recovered (pumped from the sub-surface) relatively soon after injection, 2) typically there is 

minimal formation pressure build-up during ER operations because withdrawals from oil 

recovery wells reduce reservoir pressure, which is not the case in GS reservoirs, and 3) the 

volumes of CO2 anticipated for injection for GS are significantly larger than the volumes of CO2 

injected for ER operations. 

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In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found 

that Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those 

that inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., 

in the presence of water or aqueous formation fluids), there is a potential risk factor for MIT 

failure and, for this reason, EPA believes that the tailored MIT requirements in the final GS rule 

are appropriate. 

Because of the unknown long-term effects of CO2 GS, EPA chose a more conservative initial 

approach in the early stages of deployment for GS. EPA adds that it is using an adaptive 

approach to regulating GS. The Agency plans to collect and review data every six years on GS 

projects, including MIT data, 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: 0190 Comment ID: 24538 Letter Lines: 3890 to 3896 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: in this case as well. The MIT should test integrity of the long string casing, 

packer, and tubing and to the extent practicable, should test the integrity of 

the cement isolating the injection zone. There are many methods for conducting 

MITs. EPA should allow operators adequate flexibility in selecting the 

appropriate methods for their specific situation. API RP90 provides good 

examples of various methods for detecting mechanical failures, managing those 

risks, and conducting MITs. 

Individual Response: EPA believes that the MITs described in the rule at §146.89 are effective 

methods and have been used successfully by injection well operators for decades and provide an 

important early warning of potential problems in the injection well system. 

EPA agrees with the commenter that flexibility to choose appropriate MITs is important, and the 

GS rule affords this flexibility by requiring the owner or operator to prepare and gain approval 

for a project-specific testing and monitoring plan that includes MITs at §146.90. EPA clarifies 

that the regulation provides the Director discretion to require additional methods or, with the 

Administrator's approval, to approve the use of alternative MIT methods based on specific 

information about the site or the well. See §146.89(e). 

In addition, EPA is using an adaptive approach to regulating 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. 

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Letter ID: 0190 Comment ID: 24539 Letter Lines: 3898 to 3910 

Comment Code: 4650 2.6.5 CO2 plume and pressure front tracking (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 146.90 

EPA Preamble Question: 30. EPA seeks comment on the requirement for monitoring 

of GS sites for the purpose of tracking the location of the CO2 plume and 

associated pressure front over time. EPA Notice 43514 

CSC Response: The amount of monitoring required to track plumes and pressure 

fronts is not cost justified in comparison with taking the necessary steps to 

demonstrate containment. The primary focus should be on making sure that the 

plume and formation fluid are contained within the injection zone rather than 

trying to show the exact location of the plume within that containment. 

The frequency of monitoring should be dictated by site-specific operational and 

geologic conditions combined with the results of monitoring. . 

Individual Response: EPA clarifies that all of the monitoring requirements in the GS rule are 

for the purpose of ensuring containment so that USDWs are protected from endangerment. EPA 

believes that knowing the extent of the CO2 plume and pressure front is necessary to make such 

a determination. 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. 

Pressure monitoring within the injection zone is necessary because any such monitoring above 

the confining zone would not detect movement of the pressure front unless a breach of the 

confining zone occurs. EPA believes that monitoring using wells in the injection zone (i.e., that 

penetrate the confining zone) can be safely performed if the wells are constructed to prevent flow 

between the injection zone and USDWs or other layers above the confining zone. Such 

construction technologies exist and have been used in the oil and gas industry for years. EPA 

believes that the benefits of monitoring in the injection formation outweigh the manageable risk 

of those monitoring wells serving as conduits for fluid movement. EPA adds that owners or 

operators may consider performing additional pressure monitoring in wells that are above the 

confining zone (e.g., in the same wells used to perform ground water quality monitoring required 

at §146.90(d)) to provide additional verification that no pressure changes are occurring above the 

confining zone due to CO2 leakage. 

EPA adds that all monitoring will be conducted pursuant to the approved testing and monitoring 

plan, which should be based on site-specific information about the site and planned operations. 

Letter ID: 0190 Comment ID: 24540 Letter Lines: 3912 to 3922 

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Comment Code: 4640 2.6.4 Pressure fall-off testing (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 146.90(f) 

EPA Preamble Question: 31. EPA’s proposal would require that owners or operators 

perform a pressure fall-off test at least once every five years. EPA seeks 

comment on the use and frequency of pressure fall-off testing for GS wells. EPA 

Notice 43515. 

CSC Response: We recommend that an initial falloff test be conducted upon 

completion of the well prior to any operational injection and after the first 

year of operational injection. Following the first year, the frequency should be 

at the discretion of the Director but the frequency should be aligned with the 

reevaluation of the AoR. 

Individual Response: EPA believes that a frequency of at least once every five years, as 

specified at §146.90(f), is an appropriate interval for pressure fall-off testing (particularly given 

the suite of tests operators will perform on the well and the site). EPA clarifies that the Director 

may require more frequent pressure fall-off tests at a specific project, if necessary based on sitespecific circumstances. Pressure fall-off tests may be conducted in conjunction with other well 

performance tests (i.e., mechanical integrity testing) to ensure safe and effective operations. All 

monitoring data collected, including information from pressure fall-off tests, will be incorporated 

in AoR reevaluations conducted at least every five years. 

Letter ID: 0190 Comment ID: 24541 Letter Lines: 3924 to 3935 

Comment Code: 4650 2.6.5 CO2 plume and pressure front tracking (seeking comment) 

Comment Code: 4655 2.6.5.1 Plume tracking techniques/geophysical methods (seeking 

comment) 

Comment: Rule Provisions or Federal Register Cite: 146.90(g) 

EPA Preamble Question: 32. Based on information evaluated to date, EPA believes 

that tracking the plume and pressure front is an important companion step to 

address any uncertainties associated with initial AoR modeling and requests 

comment on this approach and more efficient alternatives that may be used to 

track the plume and pressure front. EPA Notice 43516. 

CSC Response: Uncertainties associated with AoR determinations may be addressed 

through the use of a conservative modeling approach. Requirements to "track" 

plumes or pressure fronts would be extraordinarily burdensome and are not 

necessary, as extensive experience with "no migration" exemptions for hazardous 

waste injection wells has shown. 

Individual Response: EPA disagrees that plume and pressure front monitoring are not justified 

for Class VI wells. The Agency recognizes that while there are similarities between injection of 

hazardous wastes for disposal (Class I) and GS (Class VI), there are significant differences as 

well. Important unique considerations for GS include the buoyancy of CO2, its corrosivity when 

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in contact with water, its low viscosity (i.e., high mobility), and the very large injection volumes 

that are anticipated. There is also a degree of uncertainty regarding the behavior of large volumes 

of CO2 in the subsurface after injection. Given these characteristics of anticipated GS projects, 

EPA believes that plume and pressure front monitoring at §146.90(g) are justified to provide 

early warning of any unforeseen fluid movement that might endanger USDWs. 

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. 

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 also assure the public that 

GS projects are proceeding according to plan, provide sufficient information to the owner or 

operator and Director, or allow for appropriate actions to address any indication that USDWs 

may be endangered. 

Letter ID: 0190 Comment ID: 24542 Letter Lines: 3937 to 3953 

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

comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43517 

EPA Preamble Question: 33. 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 Director-approved monitoring plan for GS sites. EPA Notice 43517. 

CSC Response: Monitoring techniques and frequency should be determined on a 

site-specific basis. Selection of monitoring types and frequency should balance 

the potential risks posed by the project with the cost and potential utility of 

monitoring. 

Surface and soil gas monitoring does not add value to the protection of USDWs. 

Many of the surface and soil gas monitoring techniques currently being evaluated 

lack the track record necessary for use in a regulatory compliance setting. 

Moreover, the potential for false-positives could undermine public confidence in 

GS technologies. 

Individual Response: EPA acknowledges that air and soil gas monitoring to ensure USDW 

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protection is not necessary at all GS sites and agrees that the decision to use surface monitoring 

and the selection of monitoring methods for the purpose of USDW protection will be sitespecific. 

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. EPA also 

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. 

In the final rule, at §146.90(h), the decision to require such monitoring as an additional measure 

to ensure USDW protection rests with 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). 

Letter ID: 0190 Comment ID: 24543 Letter Lines: 3955 to 3977 

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment) 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provisions or Federal Register Cite: 146.90, 146.93(a), 146.94(a) 

EPA Preamble Question: 34. 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 post-injection site care and site closure plan. 

EPA seeks comment on the merits of requiring plans for monitoring, AoR, and 

post-injection site care as part of a permit application. EPA Notice 43517. 

CSC Response: The development of such plans is a good idea because it negates 

prescriptive regulation of the process. CSC is concerned that every modification 

of a plan may trigger a major permit modification, although it does not appear 

that current regulations would require that result. If major permit 

modifications were required, EPA would lose the adaptability desired for 

responding to experience gained from GS projects. 

It is unclear how the construction, operation, and closure of any monitor wells 

would be regulated, since these are not actual injection wells. 

Timing of development of plans should be linked to the actual activity being 

addressed (i.e. staged). It should not be necessary to prepare and submit a site 

closure plan or the post-closure monitoring plan at the start of the project, 

particularly considering that these activities will not occur for many years 

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after the project starts. 

Individual Response: EPA agrees with commenters that developing and following testing and 

monitoring plans is an important part of assuring that a GS project is operating properly and is 

crucial for the early detection of potential endangerment to USDWs. EPA expects that the 

number of monitoring wells needed will be determined based on site-specific information. EPA 

also agrees that periodic updates to the plan are appropriate. EPA clarifies that the final GS 

regulation includes a requirement that the AoR be reevaluated at least every five years, and it 

specifies at §146.90(j) that the operator revise the testing and monitoring plan to incorporate the 

results of the most recent AoR reevaluation and recent operational and monitoring data. 

EPA clarifies that every revision to the testing and monitoring plan will not necessarily trigger a 

major permit modification. The existing regulation at 40 CFR 144.39(a) identifies causes for 

modification of permits that would invoke the public notification procedures at 40 CFR 124. In 

the final rule, EPA added text to §144.39(a)(5) that permit modifications would be required if the 

Director determines that a modification is necessary based on an AoR reevaluation, amendments 

to any of the project plans, or a review of the testing and monitoring results. 

In addition, 40 CFR Part 144.41 identifies causes for minor modifications of permits (which do 

not require following the procedures of Part 124). In the final rule, EPA added a subparagraph 

(h) to §144.41 that would include minor amendments (e.g., to clarify, correct, or update) to the 

testing and monitoring plan, plugging plan, post-injection site care and site closure plan, or 

emergency and remedial response plan for a GS well (i.e., amendments that are not included 

under 144.39(a)(5) and that do not require additional permit requirements). 

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

Directors in evaluating requirements under §146.90. The guidance can be found on EPA’s 

website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. In addition, in 

January 2009, DOE published a best practices manual entitled "Monitoring, Verification, and 

Accounting of CO2 Stored in Deep Geologic Formations" (DOE/NETL-311/081508); this 

manual is included in the docket for the final GS rule. EPA notes that closure of monitoring 

wells should be addressed in the post-injection site care and site closure plan. 

EPA also believes that it is appropriate to require owners and operators to submit all plans, 

including the injection well plugging and post-injection site care and site closure plans, at the 

time of permit application. EPA believes that the Director needs a satisfactory level of assurance 

that the owner or operator has planned for these events before injection commences and that the 

owner or operator has ensured that appropriate financial resources are available to fund all 

required activities, as required at §146.85. The final rule retains requirements for submitting 

these plans with the permit application at §146.82(a). 

Letter ID: 0190 Comment ID: 24544 Letter Lines: 3979 to 3985 

Comment Code: 4760 2.7.6 Proposed reporting frequency (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 146.91 

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EPA Preamble Question: 35. EPA seeks comment on the frequency of all proposed 

reporting requirements. EPA Notice 43517 

CSC Response: Frequency should reflect the level of risk associated with the 

activity. Semi-annual reporting is adequate. Reporting should be on a project 

basis as opposed to a well basis consistent with 146.23(c). 

Individual Response: EPA is retaining the semi-annual reporting requirements as proposed at 

§146.91(a). These requirements ensure the Director has the information needed to take 

preventive action in a timely manner to protect USDWs from endangerment. See the final rule 

and preamble for further discussion on EPA's final approach to reporting and recordkeeping. 

EPA disagrees that reporting should be on a project, rather than a per well, basis. EPA notes that 

operators who want to streamline their reporting schedules can negotiate with the permitting 

authority to establish a schedule that allows reporting on all wells in a GS project at the same 

time; however, data for each well must be reported separately and at least as frequently as 

required at §146.91. 

EPA is using an adaptive approach to regulating GS. The Agency plans to, every six years, 

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: 0190 Comment ID: 24545 Letter Lines: 3987 to 3996 

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 146.91(c) 

EPA Preamble Question: 36. EPA seeks comment on the requirement for electronic 

reporting in its proposed rule. EPA Notice 43518. 

CSC Response: Industry’s objections to prior proposals for electronic reporting 

have been with the scope and breadth of information (incremental over written 

reports) that the Agency has previously proposed. Electronic reporting 

equivalent to existing written reports would be acceptable to CSC. Until these 

concerns related to electronic reporting are resolved, such reporting may be 

encouraged but should not be required. 

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

submitting Class VI project information to the Director, and based on comments received on the 

proposed rule, the majority of Class VI well owners or operators will have the capability to 

report electronically, and requires this at §146.91(e). 

EPA is developing guidance for states that describes the recordkeeping, reporting, and additional 

data management needs associated with GS activities and provides recommended guidelines on 

the types of data to be collected for tracking GS projects, reporting to EPA for compliance 

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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: 0190 Comment ID: 24546 Letter Lines: 3998 to 4008 

Comment Code: 4750 2.7.5 Comments on the merit of annual reports (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43518 

EPA Preamble Question: 37. In addition to the above recordkeeping and reporting 

requirements, EPA considered a requirement for owners or operators of GS sites 

to provide an annual report during the lifetime of the project, including the 

post-injection period, regarding the GS operation. 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 43518. 

CSC Response: An additional annual report is not necessary given the other 

reporting requirements in the Rule. Alternatively, if this report was to replace 

the other reporting requirements, there would be value to the proposal. 

Individual Response: The final GS regulation retains the reporting requirements as proposed 

and 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. 

Letter ID: 0190 Comment ID: 24547 Letter Lines: 4010 to 4051 

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

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Comment: Rule Provisions or Federal Register Cite: 73 FR 43519-20, 146.93(b) 

EPA Preamble Question: 38. EPA is proposing using a combination of fixed 

timeframe and a performance standard as described above. EPA is tentatively 

proposing a post-injection site care (monitoring) period of 50 years with 

Director’s discretion to change that period to lengthen or shorten the 50 year 

period if appropriate. EPA requests comment on the proposed use of a tentative 

50 year fixed timeframe that could be modified at the Director’s discretion 

based on monitoring and modeling data. EPA Notice 43519. 

CSC Response: We believe there are three problems with the closure standard in 

proposed section 146.93(b). First, the presumption that monitoring should 

continue for 50 years is unnecessary and counterproductive. A straight 

performance standard is preferable to this or any other fixed time period 

because it provides a clearer standard and an incentive to maximize the 

understanding of site and project performance and as such is more protective of 

USDWs. Second, the proposal requires a showing that the CO2 plume has 

"stabilized", which is undefined. Cessation of plume movement is not necessarily 

essential to show that a project poses no threat of endangerment to USDWs-plumes 

that are still moving may, nonetheless, remain contained. Instead, it is more 

protective to show that the plume is not expected to encounter a leakage 

pathway. Third, the required showing that "no additional monitoring is needed" 

does not provide guidance regarding how an operator is to show that no 

additional monitoring is needed. The proposal below provides specific guidance 

on what the operator must show. 

We recommend the standard in the proposed alternative language for section 

146.93(b) because it sets forth detailed criteria, all of which must be 

satisfied, to demonstrate that the site does not pose an endangerment to USDWs. 

The specific criteria listed in our proposal will serve to provide the Director 

with the requisite information to make the appropriate determination. The 

advantage of this approach is that it establishes clear criteria that an 

operator must demonstrate before obtaining site closure based upon particular 

site characteristics and is, therefore, reasonably applicable to any storage 

site as opposed to a standard based upon a fixed-duration. Furthermore, it is 

more stringent than a purely discretionary approach because it establishes 

specific criteria that must be shown before site closure may be granted. We 

believe this language, which is an extension of work done by the World Resources 

Institute and the Ground Water Protection Council, avoids the noted shortcomings 

and provides stronger protection for USDWs. 

This is the same recommendation as presented by the multi-stakeholder group, in 

which the Carbon Sequestration Council participated 

Individual Response: EPA disagrees with the suggested changes. As noted above, EPA 

disagrees that a post-injection site care timeframe of 50 years is excessive for most Class VI 

wells. 

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EPA acknowledges the concerns of some commenters that there will be circumstances where it 

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

of endangerment to USDWs. For this reason, the GS rule offers owners or operators flexibility 

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

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

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

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

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

USDWs pursuant to requirements at §146.93(c). 

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

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

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

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

and evaluation of public comments. 

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

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

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

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

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

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

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

impacts. 

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

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

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

recommended approaches for how an owner or operator could plug injection and monitoring 

wells, perform post-injection monitoring, demonstrate the appropriateness of an alternative postinjection site care time frame, demonstrate non-endangerment, and perform site closure 

activities. This guidance will be available at 

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

Letter ID: 0190 Comment ID: 24548 Letter Lines: 4053 to 4060 

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

Comment: Rule Provisions or Federal Register Cite: 146.93 

EPA Preamble Question: 39. EPA is requesting comments on the proposed 

requirements for well plugging, post-injection site care, and site closure, 

including the proposed requirements for the post-injection time period. EPA 

Notice 43520. 

CSC Response: See response to Question 38 above regarding post closure time 

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periods. 

Individual Response: As described above, EPA acknowledges 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 includes a 

provision that the Director may, at his/her discretion, shorten the post-injection site care time 

frame if the owner or operator can demonstrate that the GS project does not pose a risk to 

USDWs, as specified in §146.93(b)(2). Alternatively, the final rule at §146.93(c), also allows the 

Director to approve an alternative post-injection site care timeframe where an owner or operator 

can demonstrate during the permitting process that an alternative post-injection site care 

timeframe, other than the 50 year default, is appropriate and ensures non-endangerment of 

USDWs. The demonstration must be based on site-specific information, including the results of 

site-specific computational modeling; the predicted timeframe for pressure decline; the predicted 

rate of carbon dioxide plume migration; site-specific chemical processes that will result in 

carbon dioxide trapping; the predicted rate of carbon dioxide trapping; characterization of the 

confining zone(s); laboratory analyses or studies to verify the information on trapping; the 

presence of potential conduits for fluid movement and the quality of abandoned well plugs 

within the AoR; the distance between the injection zone and the USDWs above and/or below the 

injection zone; and any additional site-specific factors determined by the Director. The 

demonstration must meet the criteria at §146.93(c)(2) for ensuring the quality and accuracy of 

the data and models on which the demonstration is based. This demonstration would be 

submitted as part of the permit application, per §146.82(a)(18), in addition to the PISC and site 

closure plan required at §146.82(a)(17). 

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

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

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

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

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

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

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

impacts. 

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 required under §146.92 and §146.93. The guidance describes 

recommended approaches for how an owner or operator could plug injection and monitoring 

wells, perform post-injection monitoring, demonstrate the appropriateness of an alternative postinjection site care time frame, demonstrate non-endangerment, and perform site closure 

activities. This guidance will be available at 

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

Letter ID: 0190 Comment ID: 24549 Letter Lines: 4062 to 4069 

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

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Comment: Rule Provisions or Federal Register Cite: 146.93(b)(2) 

EPA Preamble Question: 40. 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 43520. 

CSC Response: See response to Question 38 above regarding post closure time 

periods. 

Individual Response: As described above, EPA acknowledges that there will be circumstances 

where it can be demonstrated in less than 50 years that the plume and pressure front no longer 

pose a risk of endangerment to USDWs. For this reason, the GS rule offers owners or operators 

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

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

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

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

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

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

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

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

recommended approaches for how an owner or operator could plug injection and monitoring 

wells, perform post-injection monitoring, demonstrate the appropriateness of an alternative postinjection site care time frame, demonstrate non-endangerment, and perform site closure 

activities. This guidance will be available at 

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

Letter ID: 0190 Comment ID: 24550 Letter Lines: 4071 to 4084 

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

CFR 146.85) 

Comment: Rule Provisions or Federal Register Cite: 144.36 

EPA Preamble Question: 41. Current UIC guidance describes trust funds as a form 

of financial assurance. The owner or operator may deposit funds into the trust 

fund in phases; that is, either over the term of the initial permit or over the 

remaining operating life of the injection well, as estimated in the well 

plugging plan, whichever period is shorter. Because of the possibility that the 

owner or operator may face financial distress prior to the trust being fully 

funded, 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. EPA Notice 43521. 

193
CSC Response: Industry should have a variety of options for meeting financial 

assurance based upon the companies’ discretion. Options should include selfinsurance, insurance, surety bonds or other appropriate financial instruments. 

Individual Response: 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)). The qualifying methods are listed in 

§146.85(a). 

Owners or operators may select different instruments for specific project activities. EPA also 

anticipates that the availability of third-party GS financial instruments will grow in response to 

demand for such instruments by GS well owners or operators. See the final rule and preamble for 

further discussion of EPA's final approach for financial responsibility. 

Letter ID: 0190 Comment ID: 24551 Letter Lines: 4086 to 4102 

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

comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43521 

EPA Preamble Question: 42. 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 43521. 

CSC Response: EPA should leave the door open for establishing financial 

mechanisms on a project by project basis. The rulemaking should not prescribe or 

preclude particular financial instruments. The issue of financial assurance is 

complex and must be considered in significant detail and should be based on the 

initial experience gained from the use of FA mechanisms before any guidance or 

regulation is issued. 

Individual Response: Owners or operators may choose from a variety of financial instruments 

to meet their financial responsibility obligations under the rule, provided the Director determines 

that the operator's proposed financial responsibility demonstration is adequate to protect USDWs 

from endangerment, which means the ability of the owner or operator to pay for each activity for 

194
which financial responsibility must be demonstrated, including corrective action on wells in the 

AoR, injection well plugging, PISC and site closure, and emergency and remedial response 

throughout the life of the project. The final GS rule specifies at §146.85(a)(1) the permitted types 

of financial responsibility instruments. See the final rule and preamble for further discussion of 

EPA's final approach to financial responsibility. 

Letter ID: 0190 Comment ID: 24552 Letter Lines: 4104 to 4112 

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

comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43522 

EPA Preamble Question: 43. 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 43522. 

CSC Response: See response to Question 41 above. 

Individual Response: As described above, owners or operators may choose from a variety of 

financial instruments listed in §146.85(a) to meet their financial responsibility obligations, 

provided the Director determines that the operator's proposed financial responsibility 

demonstration is adequate to pay for each activity for which financial responsibility must be 

demonstrated, including corrective action on wells in the AoR, injection well plugging, PISC and 

site closure, and emergency and remedial response. 

Letter ID: 0190 Comment ID: 24553 Letter Lines: 4114 to 4121 

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

comment) 

Comment: Rule Provisions or Federal Register Cite: 146.85 

EPA Preamble Question: 44. EPA is requesting comments on whether financial 

responsibility mechanisms to be recommended in EPA guidance should be adjusted 

in the manner described, whether additional instruments should be included, and 

whether other adjustments to the financial responsibility mechanisms should be 

considered, all subject to EPA’s authority under the SDWA. EPA Notice 43522. 

CSC Response: See response to Question 41 above. 

Individual Response: As described above, owners or operators may choose from a variety of 

financial instruments listed in §146.85(a) to meet their financial responsibility obligations, 

provided the Director determines that the operator's proposed financial responsibility 

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demonstration is adequate to pay for each activity for which financial responsibility must be 

demonstrated, including corrective action on wells in the AoR, injection well plugging, PISC and 

site closure, and emergency and remedial response. 

Letter ID: 0190 Comment ID: 24554 Letter Lines: 4123 to 4136 

Comment Code: 5436 2.9.1.3 Allowing separate financial demonstrations for plugging and 

abandonment and post-injection site care (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43522 

EPA Preamble Question: 45. The Agency is also requesting comment on allowing 

separate financial demonstrations to be submitted for the plugging of the 

injection well and for the post-injection site care requirements. EPA Notice 

43522. 

CSC Response: We support the use of separate financial demonstrations for the 

plugging of the injection well and for the post-injection site care requirements 

based on the greater experience with well plugging requirements and methods. It 

will be easier to retain certainty for these actions and to use established FA 

methods. 

EPA should look into the options available for single bonding with phased 

release and multiple bonding, as is done under SMCRA. 

Individual Response: EPA clarifies at §146.85(a)(6) that, prior to obtaining a Class VI permit, 

an owner or operator may demonstrate financial responsibility by using one or multiple 

qualifying financial instruments for specific GS activities, thereby realizing greater flexibility 

and cost savings from this regulation. In the event that the owner or operator combines more than 

one instrument for a specific GS activity (e.g., well plugging), such combination must be limited 

to instruments that are not based on financial strength or performance (i.e., self insurance or 

performance bond), for example trust funds, surety bonds guaranteeing payment into a trust fund, 

letters of credit, escrow account, and insurance. In this case, it is the combination of instruments, 

rather than the single instrument, which must provide financial responsibility for an amount at 

least equal to the current cost estimate. 

Additionally, the final GS rule, 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. Owners or operators must also adjust the estimates for inflation annually 

under §146.85(c)(2). EPA adds that the Director can also require the owner or operator to 

provide an adjustment of the cost estimate if the Director determines that the original 

demonstration is no longer adequate, as specified at §146.85(e). 

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

include a discussion on how best to estimate costs to assist Class VI well owners or operators, 

third party insurers or providers of financial instruments, and permitting authorities in 

196
developing estimates of the costs associated with various GS activities. EPA will also discuss 

how to evaluate the appropriateness of single and multiple bonding and phased release of bonds 

in the guidance. EPA will review the requirements under SMCRA as it develops the guidance 

and incorporate any relevant information. This guidance will be available on EPA's website at 

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

Letter ID: 0190 Comment ID: 24556 Letter Lines: 4152 to 4161 

Comment Code: 5560 2.10.3 Enhancing the public participation process (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43522-23 

EPA Preamble Question: 47. EPA also requests comment on ways to enhance the 

public participation process, including engaging communities in the site 

characterization process as soon as candidate locations are identified. EPA 

Notice 43523. 

CSC Response: CSC does not believe that the public participation process should 

be extended to the site characterization stage of a GS project, particularly 

given that many sites might be characterized in the process of winnowing down 

the portfolio of potential sites. 

Individual Response: The Agency believes that public participation is an important part of the 

UIC permitting process and wants to ensure wide access to decision-making processes and 

information on projects that may affect the public. GS permitting authorities must follow the 

existing public participation requirements for UIC permits as specified in 40 CFR Part 124. 

Generally, these regulations require the Director to notify the public regarding the availability of 

the draft permit and allow him or her to request a public hearing on the draft permit. EPA 

encourages operators and permitting agencies to begin involving the public by providing 

information as early in the process as possible. Such information exchange can affect how the 

local community and surrounding communities perceive potential environmental, economic, or 

health effects. 

Furthermore, the Agency recognizes that the initial phases of site evaluation and site selection 

may begin in advance of permit application submission. The public may become aware of these 

activities and begin to have questions or concerns about the pending project. For this reason, 

outreach and education—which are outside of, but complementary to, the public notification 

process—can help clarify project details and avoid public misperceptions about the nature and 

safety of GS projects. This may also benefit the owner or operator by improving local acceptance 

of the site. 

Letter ID: 0190 Comment ID: 24557 Letter Lines: 4163 to 4174 

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

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Comment: Rule Provisions or Federal Register Cite: 73 FR 43523 

EPA Preamble Question: 48. To gain authority for Class VI wells, States, 

Territories, and Tribes will be required to show that their regulations are at 

least as stringent as, and may be more stringent than, the proposed minimum 

Federal requirements (e.g., inspection, operation, monitoring, and recordkeeping 

requirements that well owners or operators must meet). Such Primacy States, 

Territories, and Tribes are authorized under Section 1422 of the SDWA. EPA 

Notice 43523. 

CSC Response: States should be able to gain primacy as long as they meet the 

requirements of the UIC program for obtaining and retaining primacy. EPA should 

ensure that adequate funding is provided for the delegated program. 

Individual Response: EPA agrees that states should be able to receive primacy for Class VI 

wells. EPA adds that States, Tribes, or Territories may obtain Primacy for Class VI wells (under 

Section 1422 of the SDWA) if they demonstrate that they have requirements that are at least as 

stringent as the federal Class VI requirements; have the authority to inspect and assess 

construction and operation of the wells as well as have the necessary legal authorities to take 

administrative, civil, and criminal enforcement actions required by the SDWA under §1423; 

impose criminal, civil, and administrative penalties on owners and operators for non-compliance 

with regulatory requirements; and demonstrate sufficient/appropriate technical capacity (e.g., 

personnel, infrastructure, and technical expertise) to implement their Class VI program. 

EPA acknowledges that there may be technical and administrative challenges including resource 

concerns, and will work closely with the states to assist them in resolving funding issues or 

acquiring the resources, personnel, and training needed to address the unique technical 

challenges associated with GS. 

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

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

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

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

matching requirement. 

Letter ID: 0190 Comment ID: 24558 Letter Lines: 4176 to 4193 

Comment Code: 5610 2.11.1 Allowing partial primacy for Class VI wells (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43523, 73 FR 43529 

EPA Preamble Question: 49. There may be benefits to parsing out primacy for 

Class VI wells, however EPA has not made a decision on this. Allowing States, 

Territories, and Tribes to acquire primacy for only Class VI wells may encourage 

them to assume the responsibility of implementation and provide for a more 

comprehensive approach to managing CCS projects (e.g., capture, transportation, 

and geologic sequestration). EPA is seeking comment on the merits and possible 

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disadvantages of allowing primacy approval for Class VI wells independent of 

other well classes. EPA Notice 43523. 

CSC Response: CSC supports separate primacy for Class VI. The geologic variation 

across the country justifies separate primacy determinations. The final rule 

should also preserve state authority to determine what agencies will exercise 

primacy. Moreover, EPA should provide adequate funding, which will require a 

substantial increase above current funding levels both to meet existing program 

needs and to provide the additional resources anticipated to be necessary for 

the Class VI program. These increases need to be provided in time to ramp up of 

resources, personnel, and training in advance of the anticipated heavy demand. 

Individual Response: As described above, EPA agrees with commenters that states should be 

allowed to obtain primacy for Class VI wells independently of other well classes, and will allow 

independent primacy for Class VI wells under §145.1(i) of the final GS rule. EPA also clarifies 

that primacy is granted to a state, not to any agency within that state, and states are free to choose 

which agency will implement the Class VI program—for instance, an environmental quality 

protection agency (non-Class II) or the state's traditional oil and gas regulatory agency (Class 

II)—as long as the program meets the minimum Federal requirements for Class VI wells as 

required under section 1422 of SDWA. Some states administer their program for all injection 

well classes through a single agency, whereas other States elect to divide the program between 

agencies. For example, in most States, the Class II program is run by an oil and gas agency and 

other well classes are run by a State environmental agency (e.g., the Oklahoma Corporation 

Commission oversees Class II wells in the State, and the Oklahoma Department of 

Environmental Quality oversees other well classes). Additionally, several States allow their oil 

and gas agencies to administer their UIC program for specific well classes or subclasses provided 

they meet all Federal requirements (e.g., the Texas Railroad Commission oversees Class III 

brine-mining wells and Class V geothermal wells in Texas). EPA believes that retaining this 

flexibility for States to identify the appropriate agency to oversee Class VI wells will address 

commenters’ concerns that States should be afforded the opportunity to determine which agency 

should oversee Class VI wells, and recognizes the existing expertise of both State oil and gas 

agencies and environmental agencies. 

EPA acknowledges that there may be technical and administrative challenges including resource 

concerns, and will work closely with the states to assist them in resolving funding issues or 

acquiring the resources, personnel, and training needed to address the unique technical 

challenges associated with GS. 

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

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

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

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

matching requirement. 

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Letter ID: 0190 Comment ID: 24559 Letter Lines: 4138 to 4150 

Comment Code: 5520 2.10.1 Appropriateness of existing public participation requirements 

(Part 25 and Part 124) for GS (seeking comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43523 

EPA Preamble Question: 46. EPA requests comment on adopting the existing 

requirements for public participation at 40 CFR Part 25 and 40 CFR Part 124 and 

whether additional requirements should be included to reflect the availability 

of new tools for disseminating and gathering information. Such tools include 

cable networks, the Internet, and other new technology. EPA Notice 43523. 

CSC Response: The current provisions in Parts 25 and 124 are sufficient to 

inform the public. Additional requirements should not be included. 

Public participation should be consistent across programs. If EPA believes the 

public participation requirements should be expanded, it should be done in a 

holistic manner across programs. 

Individual Response: EPA agrees that the existing UIC public participation requirements as 

specified in 40 CFR 25 and 40 CFR 124 are appropriate for GS projects. In addition, because of 

the unique nature of GS projects, and the anticipated level of public interest in GS projects, EPA 

encourages early public involvement in GS projects. Providing the public with accurate, projectspecific information in the early stages of each GS project can help clarify project details and 

avoid public misperceptions about the nature and safety of GS projects, and will allow a potential 

GS owner or operator and the permitting agency to address the public's concerns before the 

permitting process is complete. 

In response to the suggestion to apply additional public participation requirements to all injection 

well classes, EPA notes that this is beyond the scope of the GS rulemaking. 

Letter ID: 0190 Comment ID: 24560 Letter Lines: 4195 to 4206 

Comment Code: 5700 2.12 Comments on the proposed duration of Class VI permits (seeking 

comment) 

Comment: Rule Provisions or Federal Register Cite: 144.36(a) 

EPA Preamble Question: 50. EPA proposes that Class VI injection well permits 

would be issued for the operating life of the GS project including the postinjection site care period. EPA seeks comment on the merits of this approach. 

EPA Notice 43523. 

CSC Response: A permit for the life of the project would ensure the continuity 

of operations. Shorter time periods would yield administrative burden without 

commensurate benefits. The development of AoR, plans, and other parts of the 

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permitting process must be addressed on a project-wide basis. Therefore it is 

important for permits to last for the operating life. It is also sensible to 

allow for area permits. 

Individual Response: EPA agrees with commenters that Class VI permits should be issued for 

the operating life of the GS project. The final rule maintains the lifetime permit provision and 

clarifies that the permit extends through the post-injection site care period (144.36(a)). However, 

it also adds a requirement that the Director review each Class VI permit at least every five years 

to determine whether it should be modified, revoked and reissued, terminated, or a minor 

modification made as provided in §§144.39, 144.40, or 144.41. The Director’s review will be 

informed by the owners’ or operators’ iterative reevaluation of the project. Specifically, the final 

rule includes a requirement that the AoR be reevaluated at least every five years, and also 

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 (146.84(e), 146.90(j), and 146.94(d)). Owners or operators must review each plan and 

identify necessary amendments or demonstrate to the Director that no amendment is needed. In 

no case can reviews occur less often than once every five years. 

EPA adds that the required reviews of the AoR and corrective action plan, the testing and 

monitoring plan, and the emergency and remedial response plan throughout the life of the project 

are preferable to a periodic permit reapplication. The iterative process and subsequent plan 

reevaluations ensure that time and resources are committed to the most critical aspects of the 

permit in preventing endangerment to USDWs. 

EPA disagrees that area permits are appropriate for Class VI wells. The Agency believes that 

individual injection well permits are essential to ensure that every Class VI well is constructed, 

operated, monitored, plugged, and closed in a manner that is protective of USDWs. 

EPA believes that the efficiencies and administrative benefits offered by area permits can be 

achieved through well executed plans required for Class VI wells. EPA envisions that planned 

additional GS wells should be discussed as part of the ongoing dialog between the owner or 

operator and the Director. For example, EPA expects the AoR plan to consider anticipated future 

wells so that the Director is able to consider all anticipated injection and resultant pressure 

changes in evaluating the plan and setting permit conditions. Similarly, testing and monitoring 

plans should account for future injection wells to ensure that ground water monitoring or CO2 

plume and pressure front tracking are planned appropriately. 

EPA also believes that requiring separate permit applications for each well will ensure that the 

public has an opportunity to provide input on each well in the field as it is constructed or brought 

online. In addition, where wells are re-permitted as Class VI wells (e.g., in ER projects, which 

may typically operate under Class II area permits), EPA believes that the unique nature of GS 

necessitates individual review of each well to ensure the re-permitted 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). 

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Letter ID: 0190 Comment ID: 24561 Letter Lines: 4208 to 4225 

Comment Code: 6220 3.2.2 Assumptions about the number of monitoring wells (seeking 

comment) 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43527 

EPA Preamble Question: 51. The Agency assumes three monitoring wells per 

injection well for the purpose of estimating national costs; however, the Agency 

recognizes that operators and primacy agency Directors may choose more or fewer 

monitoring wells depending on project site characteristics. Because the 

monitoring wells and associated costs represent a significant component of the 

Cost Analysis, the Agency acknowledges that this factor may be significant in 

the overall uncertainty of the Cost Analysis. EPA requests comment on whether 

three monitoring wells per injection well is an appropriate costing assumption. 

EPA Notice 43527. 

CSC Response: It is difficult to select a realistic ratio since each site will 

have its own characteristics that would significantly affect the number of 

monitoring wells necessary. Moreover, the potential benefit of any monitoring 

well must be determined and weighed against countervailing considerations. The 

potential for using "three monitoring wells per injection wells" is completely 

out of proportion to any prior experience in the UIC program and, hence, 

unsupportable. For many sites, monitoring wells should be unnecessary. 

Individual Response: EPA recognizes that the number of monitoring wells associated with GS 

projects will be site-specific and vary based on many factors, including the local geologic 

characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 

injected. The proposed rule Cost Analysis described the number of monitoring wells as a ratio to 

the number of injection wells; EPA clarifies that the number of injection wells was based on the 

size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly 

based on the size of the AoR. Because ER project sites have injection wells that are more 

clustered than those in saline formations, the AoR and the number of monitoring wells were 

anticipated to be smaller at an ER project site compared to a saline formation project. EPA 

retained this assumption regarding the density of injection wells for the final rule analysis, but it 

changed its assumption on the number of monitoring wells at each site. For the final rule, the 

Agency assumes one monitoring well above the injection zone per two square miles of AoR; for 

monitoring wells into the injection zone, the Agency assumes one monitoring well per four 

square miles. EPA assumes monitoring wells into the injection zone will also be used to sample 

above the injection zone. The number of monitoring wells assumed for each project type is 

presented in Exhibit 5.2 of the Cost Analysis. 

Because the actual number of monitoring wells that will be necessary for a given project site is 

uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells 

by applying a 25 percent decrease and increase in monitoring wells per project type to the 

original assumptions. This change results in annualized incremental rule costs approximately 16 

percent less and 16 percent greater than costs estimated for the primary analysis (as shown in 

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Exhibit 5.26 of the Cost Analysis). 

In response to the comment that monitoring wells will not be necessary for some GS projects, 

EPA clarifies that §146.90(d) requires monitoring of ground water quality and geochemical 

changes above the confining zone(s). In addition, direct monitoring for pressure changes in the 

injection zone, required at §146.90(g), will also necessitate the use of monitoring wells. EPA 

adds that projects operating under injection depth waivers will also monitor using monitoring 

wells below the injection zone (§146.95). For additional information on EPA's final regulatory 

approach, including testing and monitoring requirements, please see the final rule and preamble. 

Letter ID: 0190 Comment ID: 24562 Letter Lines: 4227 to 4236 

Comment Code: 7700 4.7 Executive Order 13045: Children's Health Protection 

Comment: Rule Provisions or Federal Register Cite: 73 FR 43531 

EPA Preamble Question: 52. The public is invited to submit comments or identify 

peer-reviewed studies and data that assess the effects of early life exposure to 

changes in drinking water quality that may be caused by geologic sequestration 

of carbon dioxide. EPA Notice 43531. 

CSC Response: CSC is not aware of anything unique about CO2 injection or its 

potential impacts on drinking water quality that would not be addressed within 

the existing drinking water program. The data EPA has on developing drinking 

water standards and MCLs can be used in this situation. 

Individual Response: EPA is funding research related to the potential for USDW contamination 

associated with GS projects. In addition, the Agency is tracking external research that focuses on 

potential exceedances of drinking water standards, which were developed by EPA and take into 

account impacts on children's health. 

In the August 31, 2009, Notice of Data Availability (NODA) and Request for Comment (74 FR 

44802), EPA published the results of a study in which Lawrence Berkeley National Laboratory 

(LBNL) evaluated the potential for GS to cause changes in ground water quality as a result of 

CO2 leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, 

mercury, lead, antimony, selenium, zinc, and uranium (Birkholzer et al., 2008a). LBNL 

estimated the amount of trace elements from native mineral species that could potentially be 

mobilized by the intrusion of CO2 and the potential ground water concentrations that could result 

to determine the potential for drinking water standards to be exceeded. EPA has also examined 

potential methods for conducting treatment of water affected by a CO2 leak; this study is 

presented in the final rulemaking docket. 

EPA continues to fund research in this area. In December 2009, EPA's Office of Research and 

Development (ORD) awarded a Science to Achieve Results (STAR) grant to Clemson University 

to investigate the potential for GS to affect USDWs. This research will involve laboratory 

experiments and modeling simulations to investigate the fate of dissolved CO2 in underground 

geologic formations and to determine possible risks associated with the dissolution of CO2 in 

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underground aquifers. This STAR Grant is among six such grants awarded to major universities 

and institutions focusing on: "Integrated Design, Modeling and Monitoring of Geologic 

Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water." 

EPA clarifies that the purpose of the GS rule is to protect USDWs from endangerment through 

permitting, siting, construction, operation, injection, and post-injection site care and site closure 

requirements that are tailored to address the unique nature of GS. The Class VI requirements, 

therefore, minimize health risks to all populations, including children. The "Risk and Occurrence 

Document for the Geologic Sequestration Rulemaking," available in the rulemaking docket, 

presents a broad discussion of risks to human health and the environment associated with GS, 

including those addressed under SDWA authority and those environmental and human health 

impacts that are beyond the scope of the SDWA. 

As part of its adaptive rulemaking approach, EPA plans to collect and review available 

information, such as the research described above, and data every six years on early GS projects, 

including impacts to USDWs and drinking water quality that may affect the health of children, to 

determine whether the appropriate amount and types of information and documentation are being 

collected, and to determine if modifications to the requirements are appropriate or necessary. 

Letter ID: 0190 Comment ID: 24973 Letter Lines: 2566 to 2570 

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

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(a)(2) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment; the final rule retains the requirements 

for logs to be run prior to installation of surface casing required at §146.87(a)(2). 

Letter ID: 0190 Comment ID: 29259 Letter Lines: 3686 to 3690 ; 3699 to 3703 

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

Comment: Rule Provisions or Federal Register Cite: 146.86(b) 

EPA Preamble Question: 16. 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 

43509. 

CSCopposes the requirement for cementing the long string casing back to surface. 

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Cementing requirements should focus on ensuring competent isolation and seal 

across the injection zone and confining zone(s). Sealing the annulus between the 

long string and surface casing could limit an operators ability to monitor for 

leakage or conduct remedial operations. 

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

prevent monitoring, operation, and remediation of GS wells. Cementing of deep wells has been 

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

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

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

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

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

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

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

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