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 ca rbon dioxide under the Safe Drinki ng Water Act (SDWA) "Federal Requirements Under the Underground Injection Cont rol (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells," 73 Fed. Re g. 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 seques tration (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 a pproaches for providing input to a number of ongoing processes, including the EPA’s tec hnical 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 comm ent period that allowed us to make substantial progress in expanding our shared understanding on the relevant issues an d 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, wh ich are submitted with the request that the

recommendations be considered as a whole b ecause 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 seque stration 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 additi onal 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 propos ed regulations presented in Attachment A, (3) responses to a number of specific requests for co mment presented by EPA in the preamble to the

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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 ap propriate regulations governing CO2 injection for purposes of GS. We agree that GS is an importa nt 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 injecti on 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 th at 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 su ccessful only to the extent that both of these goals

are achieved.

Fortunately, there is abundant evidence that CO 2 injection can be accomplished in a manner that is protective of human health and the environment. In deed 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 larg e 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 im pacts 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 ch allenges 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 huma n health and the environment. Because such requirements would impose regulatory burdens th at 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 st reamlined 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 Approp riate UIC Program Regulations for GS

.

We support EPA’s conclusion that the UIC prog ram provides an appropriate framework for regulation of carbon dioxide (CO 2 ) injection for geologic sequestration (GS). The UIC program governs a very wide range of underground injection activities – including the operation of thousands of existing CO 2 injection wells – and enjoys an extensive ly documented record of success. The program has in many respects been a model for Fe deral-State cooperation, and has benefited from a long history of regulatory and technical discou rse 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

CO 2 injection into oil and gas reservoirs. We also agree that it makes sense to develop regulations more specifically designed to address CO 2 injection in the GS context es pecially for formations that are not oil and gas reservoirs. Such regulations ca n and should be designed to build on relevant UIC program experience, including experience with CO 2 injection, and should be tailored to address the particular needs for this category of injection acti vity: both the need to protect USDWs and the need to facilitate use of GS as a technology for reducing CO 2 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 initia l 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 re sulted 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 like ly to pose threats of endangerment to drinking

water resources. 1 /

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

hazardous and non-hazardous waste. Clas s I injection wells provide a safe mean s 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 Re covery 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

.

CO 2 injection wells are currently permitted as Cla ss II or Class V “experimental technology” wells. Under the proposed rule, Class II CO 2 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 CO 2 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.

CO 2 injection for purposes of enhanced oil or gas recovery (“EOR/EGR”) has been successfully regulated as Class II injection for decades, and we agr ee 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 fo r regulation than the current Class V regulations.

As EPA has recognized, the creati on 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 CO 2 is injected for the purpose of GS in connection with EOR/EGR operations. EPA’s Proposal would continue to regulate and permit injection of CO 2 for EOR/EGR purposes as Class II injection “as long as any production is occurring.” EPA has as ked 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 CO 2 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 a ctivities the applicable class of wells and regulatory requirements is Class II. Furthermor e, 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 discu ssed below. This potential change in risk profile would necessitate additional requirements that ar e commensurate with both the historic EOR/EGR operations in the particular oil and gas field and wi th the risk profile of continued CO2 injection for

Class I injection wells inject far below the lowermos t USDW. Injection zones typi cally range from 1,700 to

more than 10,000 feet in depth. The injection zone is se parated from USDWs by an impe rmeable “cap” rock called the

confining layer, along with additional laye rs of permeable and impermeable rock an d sediment that separate the injection

layer from the USDW.

http://www.epa.gov/safewate r/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 paragrap h (b)(4) are not met.’” There may be a further recommendation that EP A 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 wher e there is no intent to sequester, 30-50% of the injected CO2 will remain in the reservoir after pr oduction 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 re servoirs are well studied and they offer the best opportunity to kick-start large-sc ale geologic storage of CO2 bu ilding on 100 years of oil field operating experience. Accordingly, EOR/EGR opera tions 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 therefor e clarify that EOR/EGR operations that include CO2 injection for the purpose of sequestration, or what is someti mes called “EOR with sequestration,” will remain covered by Class II requirements. EPA recognit ion 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 trad e or taxation schemes develop. As long as oil or gas production continues, this remains an EOR/E GR 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 cea se. In this situation, EPA should revise its proposal to retain the regulation of all GS in oil an d 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 th an 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 an d 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 se rvice. The preamble indicates that “the owner or operator would need to follow the permitting pr ocess outlined in today’s proposal to receive a Class VI permit,” but EPA proposes “to give the Di rector 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 en danger 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 require ments should be virtually automatic.

In addition, it is important to recognize that th e need and justification for “grandfathering” is not limited to construction requirements. There are also proposed Class VI operational and monitoring requirements that would require th e 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, th ere should be a regulatory presumption – absent some specific information to the contrary – that continued oper ation 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 modifica tion or supplementation of existing permit conditions rather than through the wholesale appl ication 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 addi tional requirements as necessary to demonstrate geologic containment of the injected CO2 stream.

C. Class VI Injection Should Not be Li mited 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 dr inking water (USDW). This re quirement 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 CO 2 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 exce llent 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 CO 2 only below the lowermost [SDW aquifer “will make it impossible to inject CO 2 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 propos ed will make geological sequestration of CO 2 impossible. To promulgate a geological CO 2 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 CO 2 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

CO 2 stream as fluid without characterizing that stream as a waste. It is neither necessary nor helpful to categorize CO 2 as a pollutant or waste, and that wo uld likely prove detrimental to technology development. Indeed, we are concerned that EPA’s brief discussion of a supposed potential for injected CO 2 streams to be characterized as hazardous wa ste (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 tec hnologies. Through the work of our engineers and scientists with capture technologies and their extensive experien ce with the types of power plant flue gas likely

to be sources of CO 2 for sequestration, we do not believe that captured CO 2 streams should trigger the application of either RCRA or CERCLA. Acco rdingly, we encourage EPA to dispel concerns that geologic sequestration could be encumbered with those requirements except possibly through the commingling of a captured CO 2 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 ma y be considered hazardous waste for RCRA purposes, and defines “carbon dioxide stream” to excl ude hazardous waste. 73 Fed. Reg. at 43503. The premise appears to be that CO2 is solid was te, and that a waste dete rmination 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 ca tegorical determination as to whether injected

CO2 is hazardous waste under RCRA.” Id

.

In fact, there are important categorical determinati ons 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 wa ste” does not include gaseous ma terial 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 “c ontained” 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 dete rmination 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 RC RA waste determination requirements.

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Again, the RCRA definition of solid waste is limi ted to “solid, liquid, semi-solid, or contained gaseous material.” RCRA 1004(27). Because su percritical CO2 is none of these things; a plain reading of the statutory text suggest s that supercritical CO2 should not be considered “solid waste.” This reading of the statute makes sense, because RC RA is plainly aimed at th e kind of material that could end up being dumped into a landfill. Unc ontained 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 – befo re it could contribute to the c ontents of a landfill. A related practical consideration is the fact that the hazard ous characteristics – the broad waste determination criteria that provide a primary means for determi ning 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 characteris tic depends on test methods that can only be applied to materials that are solids or liquids at standard temperature s 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 di scussed – 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 “so lid 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 CO 2 geologic sequestration (GS) projects. Specifically, in Section II.D. of the preamble, EPA notes several “potential USDW impacts,” including the potential that the injected CO 2 could (1) force native brines into USDWs; (2) contain impurities; or (3) cause naturally occu rring or otherwise pre-ex isting chemicals to be mobilized within the injection zone, for example, vi a 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 mobiliz ed contaminants could cause endangerment of

USDWs.” Id.

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

CO 2 considered a hazardous substance under CERCLA?” 73 Fed. Reg. at 43503-04. EPA indicates

that CO 2, while not itself a CERCLA “hazardous substance,” could contain hazardous substance impurities. EPA indicates further that “the CO 2 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 ba sic scenarios: (1) preexisting hazardous substances, or hazardous subst ance 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 rele ases. This would include clarifying if there are potential releases from the well wh ich 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 constitu te 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 lia bility 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 di scharge 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 discourage ment of development and investment in CO 2 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 accuratel y characterized as two separate exemptions.

Under CERCLA’s release reporting provisions, certa in 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, immedi ately notify the Nation al Response Center....

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42 USC § 9603(a). FPR is in turn defined to incl ude 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 underg round injection control programs or State programs submitted for Federal approval (and not disapproved by the Admini strator 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 i ssue was an authorized injection of fluids. If so, the release would not have to be reported. Th e 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. Nothin g 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 liabili ty, 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 liabilit y imposing provisions, which require a release of hazardous substances from a facility “which ca uses the incurrence of response costs.” This exemption is obviously broader than just the FPR itse lf 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 wh ether 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 circumst ances identified by EPA – in-situ reaction or mobilization, migration, etc. – remain ultimately th e result of the FPR, and would be covered by the liability exemption. In other words, but for the au thorized injection, the costs would not have been incurred. Therefore, the FPR exemption should a pply to the scenarios identified by EPA in the preamble, with the exception of costs incurred due so lely to unauthorized releases – i.e., releases resulting from unauthorized injection.

The scope of the FPR exemption in the CERCLA cleanup liability contex t has been interpreted narrowly by some courts, but none of the cases invo lved 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 rele ase 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 pe rmitted 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 proposa l, EPA should take th e 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 definiti on 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 so urce 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 stream s failing to meet this definition would fall outside the scope of the “authorized injection of fluids” unless expressly au thorized 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 migrat ion of impurities, mobilized pre-existing contaminants, or displaced brines.

Although the risk of a CO 2 GS 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 CO 2 GS projects. CERCLA’s far-reaching liab ility 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 unde veloped “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 liabili ty, 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 s hould recognize the significant chilling effect that

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CERCLA liability concerns would have on the development and deployment CO 2 GS projects, especially in this era of high volatility in the in vestment markets. EPA should use the opportunity in this rulemaking to alleviate unwarranted CERCLA lia bility 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 CO 2 GS 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 seek ing compensation for investigation response – and possibly remediation – costs claimed to be incu rred as a result of releases from geologic sequestration injection zones. The discussion of wh at might be required to acquire any necessary rights to conduct CO 2 GS projects is complex enough already without even beginning to consider how the willingness of pore space owners to particip ate 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 CO 2 GS projects.

E. EPA Should Ensure that the Regulations for GS Are Not More Stringent or Prescriptive than Nece ssary to Protect USDWs

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EPA has recognized that it has two goals for th e proposed rules for geologic storage of carbon dioxide: the protection of underground sources of drinking water 2 / 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 stor age 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 revi ew (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 Prom ising Technologies to Help Mitigate Climate Change” (July 15, 2008), http://www.epa.gov/safewa ter/uic/wells_sequestration. html (“EPA is proposing a rule that supports promising technologies to prevent industri al emissions of carbon dioxide. Secure , long-term undergro und storage of the greenhouse gas is one way scie ntific innovation could lessen the effects of climate change. . . . Carbon capture and storage is part of a portfolio of technologies available to reduce greenhouse gas em issions. EPA is coordinating with the Department of Energy on car bon sequestration research and development. ”); EPA Press Release, “EPA To Develop Regulations for Geologic Sequestration of Carbon Di oxide” (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 stig matize GS. The preamble to the proposed rule repeatedly overstates the risks posed by CO2 inj ection 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 re sult, the preamble presents an exhaustive review of every imaginable risk with re spect 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 we ll understood and relatively easy to address. The scale of GS operations will certainly be larg er than many previous CO2 injection operations, but it is not as though we do not have extensive ex perience 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 CO 2 injection wells in operation that have injected hundreds of millions of tons of CO2 largely wi thout incident. Rather than provide appropriate context for the development of Class VI regu lations, however, the proposed rule gives the impression that GS is an adventure into entirely un charted 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-bur densome, and often redundant requirements.

1. The Proposed Class VI Requirements Are Far More Burdensome than Necessary to Protect USDWs

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As the preamble acknowledges, the actual human he alth and ecological risks associated with GS are relatively remote and can be addressed effective ly 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 ru le seems to proceed from the premise that the most strict UIC regulations in exis tence – 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 foun d in abundance both in ambient air and in the subsurface – is nothing like hazardous waste and pl ainly 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 mechanic al integrity testing requirements for injection

wells; after all, what “works” in terms of th e 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 require ments 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 “grandfat her” 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 Cla ss 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 a bout 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 Burde n it Excessively Would Not be in the

Public Interest

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The magnitude of the regulatory burdens imposed by the proposed Class VI requirements are of concern for several reasons. First, unnecessary regu latory burdens would act as a direct impediment and disincentive to the development of GS proj ects. Less directly, the imposition of unreasonably stringent regulatory requirements – particularly requirements for multiple layers of requirements addressing the same basic risks – inherently magnif y 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 th e need to ensure that the public has accurate information. To facilitate the public’s appreciati on 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 concer ns. 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 financ ing. The recent turmoil in the financial markets highlights how challengin g 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 likel y 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 CO 2 can be accomplished safely and without harm to the environment as long as we apply the right knowledge base, detailed si te-specific information, technical expertise, and

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sound management practices. However, we cannot implement an effective regulatory program for sequestering CO 2 if the rules are based on the erroneous premise that CO 2 represents an extreme hazard. It is therefore important that EPA send accurate messages about the nature of CO 2 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 Prop osed Class VI Requirements

A. Geologic Siting Requirements

In view of the need to promote appropriate us e of GS to reduce CO2 emissions, the regulations should be designed to allow GS in any geologic setting in which th e Director concludes that GS can be conducted without endangering USDWs. It follows that the regulations should give the Director discretion to apply th e “non-endangerment” performan ce standard on a site-specific basis as particular geologic site conditions warrant, wit hout the need to apply prescriptive criteria that – while perhaps necessary to endure protecti on of USDWs in some cas es – 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 regul ation must be flexible, and that rigid criteria should not substitute for performance-based sta ndards and site-specific consideration of the

merits.

The preamble to the proposed rule outlines normal site selecti on 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 requirem ents 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. Unfortunatel y, the preamble goes on to suggest the need for overly-elaborate analysis of extraneous issues, a nd the rule text proposed for codification at 40 C.F.R. 146.83(b) would allow the Director a pparently unlimited discretion to impose siting conditions that go beyond those necessary to ensu re 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 seis micity 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 dem onstrating that such risks are mode st 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 e xperience with literally thousands Class II CO2 injection wells injecting hundreds of millions of tons of CO2.

The apparent extent of concer n about geochemical compatibility is particularly hard to understand. Although it is true that injection of CO 2 can be expected to lead to the formation of carbonic acid, the resulting carbonic aci d is only weakly corrosive a nd – 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 Ru le 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 [o r] group of formations” acting as a barrier to fluid movement). Considera tions 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 fo r the protection of USDWs

. Worse, the proposed rule provides no apparent limit on the Directo r’s discretion in this regard. Indeed, the preamble suggests that the Director could require de tailed 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 s hould be protection of US DWs. By authorizing extraneous siting (or site assessment) requirem ents 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 signa l 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” additiona l siting requirements.

It should be noted that a requi rement 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 doe s 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 s ubstantially more rigorous requirements than would apply in other contexts. To do so woul d 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 de termination 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 poten tial extent of CO2 plume movement – are appropriate aids to the evalua tion of geologic siting and corre ctive 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 e xploration and produc tion and has been used in the UIC program for “no-migration” pe titions 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 “t he region surrounding” the GS project that “may be impacted by the in jection activity.” 72 Fed. Re g. 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 phys ical 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 com position of the plume – that matters and there is

no need to model chemical changes. This is a critical point, b ecause 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 “t he 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 necessa ry 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 ev en required. 73 Fed. Reg. at 43507. However, fine precision generally isn’t necessary, Th e appropriate goal for m odeling is to ensure

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protection of USDWs, and conserva tive (i.e., less precise) mode ling may be sufficient and even preferable for this purpose. A quest for greater precision would not guarant ee 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, th e AOR defines the area

within which corrective action for abandone d boreholes may be necessary to prevent endangerment of USDWs. The language of the pr oposed rule (i.e., “may be impacted by the injection activity”) is not clearly limited to im pacts of the injection activity that could cause endangerment of USDW’s . It should be.

2. Corrective Action

Corrective action is a familiar UIC program requi rement. 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 period ic reevaluation of the AOR dete rmination on a frequency of at least once every ten years. We recommend an alternative approach.

Reevaluation of the AOR is a significant exer cise that ought to be triggered only when information suggests that there is actually a need for reevalua tion. At the same time, it is important to recognize that inje ction well operations provide an ongoing stream of information – injection pressure information in particular – th at 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 reeval uate 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 materia lly 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 re ports 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 accepta ble 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 dur ing 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 re sults 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 pr omptly when necessary but that there is no need to reevaluate the AOR when monitoring re sults remain consistent with modeling results such that a requirement to reeval uate the AOR would be unnecessary.

C. Injection Well Construction Requirements

1. Well Design

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

in the EOR context – have demonstrated that th e construction requirement s 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 nevert heless impose subs tantially more costly well construction requirements resembling those for Class I hazardous waste injection wells. The Proposed Rule specif ically cites the buoyanc y of CO2 as the jus tification for these requirements. See 73 Fed. Reg. at 43509.

The buoyancy of CO2 in no way justifies the a dditional construction re quirements proposed. The reason for this is straight-forward: by far th e greatest driving force fo r fluid migration along an injection well borehole is the pressure bu ild-up (or “cone of influence”) caused by fluid injection during the operation of th e injection well. The magnitude of this pressure influence is at its maximum at the point of injection, and – with in the injection interval – it generally falls off logarithmically with lateral distance from the inj ection well borehole. At some distance from the injection well, the pressure influence of the inje ction activity can be exp ected to decline to the point where density-driv en flow (i.e., buoyancy) could become significant (at l east in relative terms) as a driver for vertical fluid migrati on. At the injection we ll, however, the induced pressure gradient caused by the injection activ ity 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 injecti on well construction requirements than have already proven to be sufficient in th e case of Class II CO2 injection wells.

Our specific recommendations with respect to well constructi on are as follows.

EPA should rely primarily on the basic perfor mance 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 effec tive 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 surf ace casing cemented from the

base of USDWs to the surface. While this is a commonly- imposed requirement and is generally appropriate, th ere are some conditions (e.g., when th e base of the lowermost USDW is particularly deep) where such a requirement would be unduly burdensom e 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 disc retion of the permit writer rather than being predetermined in the

text of the rule.

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

cemented to the surface. Such a requirement – while argua bly appropriate in the case of hazardous waste injection wells – can significantly complicate we ll 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 pe rmits 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 pos itive 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 requireme nts, the proposed rule would require the use of degradation-resistant construction material s 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 inject ion in the EOR context su ggests that corrosion is a significant issue. 73 Fed. Reg. at 43509-10.

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

of CO2 and water. This distinc tion is critical from a practical standpoint, because injected CO2 streams would at least generally be “dry” (i .e., dehydrated) and theref ore non-corrosive. Once injected, the “dry” CO2 would come into c ontact with naturally-occurring water in the subsurface, creating carbonic aci d. 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 injectio n. 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

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sequestration context – there is no basis to suggest that injected CO 2 is corrosive or that injection wells must be designed and constructed to re sist a severely corrosive environment.

Class II experience with CO2 in jection 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/EG R 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 genera lly require th at 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 corros ion-resistant materials ma y be required, there is no technical basis for any general presumption th at 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 in jection well, not the ultimate duration of the GS program. The potential for longer term exposure of well compone nts after injection has ceased will depend upon – and can be mitigated by – measures im plemented 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, sa mpling and testing requirements of the proposed rule are overly rigid and prescriptive. In partic ular, the proposed rule appears to proceed from the premise that

all of the information that could usefully be ob tained 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 re spect 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 inform ation is available prior to drilling, there will be

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

value of another exhaustive set of logs, samples and tests woul d be minimal. For example, extensive logging, sampling and testing clearly s hould not be necessary where there are multiple other injection wells or st ratigraphic test wells that have been (or are being) used to gather the same kind of information for the same geologic form ations and the same area . Accordingly, it is important to ensure that logg ing and testing requirements be tailored to the circumstances involved so that that costly and duplicative l ogging, sampling and testing requirements can be

avoided.

Carbon Sequestration Council (CCS C ontact Group) 21 bdday@bryancave.comDocket 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 inje ction pressure limitati ons presented in the Joint Letter resulting from th e multi-stakeholder discussion.

2. Pressurized Annulus

The proposed rule would require a pressurized a nnulus with an annulus pressure exceeding the pressure in the injection tube. While we sup port the proposed require ment for a pressurized annulus, we oppose the requirement that annulus pressure exceed injection tube pressure.

The concept that annulus pressure should exceed in jection tube pressure was introduced in the context of hazardous waste injection, where it refl ected 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 l eak into the injection tube rather than allowing injectate to enter the annulus). The same extrem e 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 mainta in an over-pressurized annul us would not be justified.

A pressurized annulus would perm it detection of casing leaks whet her or not annulus pressure exceeds injection pressure. Similarly, any signifi cant pressure differential between in annulus and injection pressure would pe rmit prompt detection of a tubi ng leak whether or not annulus pressure exceeds injection pressu re. Accordingly, a requirement for a pressurized annulus is sufficient to protect USDWs wit hout any requirement that annulus pressure exceed injection pressure. Indeed, a requirement that annulu s pressure exceed injection pressure could - depending on the site conditions involved – do more to limit than enhance the sensitivity of leak detection. Consequently, the dete rmination 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 in jection rate, volume, and injectate temperature is also appropriate, but the pr oposed requirement for continuous monitoring of annulus fluid volume is unnecessary and (depen ding on what is actually contempl ated) impractical. There is ample UIC program experience demonstrating th at continuous monitoring of annulus fluid volume is not required for any purpose. For leak detection, pressure mo nitoring – with periodic

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

4. Down-Hole Shut-Off Valves

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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 “d own-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 constr uction 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 inj ect corrosive fluids or will always be in contact

with corrosive conditions in the injection zone. A general requi rement for corrosion monitoring is therefore unnecessary and inappropriate.

Even if there were some basis for corrosion co ncerns, a requirement fo r corrosion monitoring would be excessive, because the proposed rule already includes other provisions sufficient to

address the risks corrosion would present. In partic ular, 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 (a s we recommend) the burdensome and unnecessary provisions expressly requiring us e of corrosion-resistant material s is excised. In addition, the requirements for a tubing and packer design w ould protect against corrosion leaks, both by providing secondary containment of the inject ate and by permitting continuous annulus pressure monitoring (also required) to ensure that corrosi on 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 injecti on to either to any minimum injection depth or to injection zones below th e 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 ap propriate CO2 storage reservoirs. EPA should permit GS under any circumstances in which the Di rector can determine that USDWs will not be endangered.

Recognizing that the USDW definition is so broa d 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.

Carbon Sequestration Council (CCS C ontact Group) 23 bdday@bryancave.comDocket ID No. EPA–HQ–OW–2008–0390 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 di scretion 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 os tensibly 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 loca lized information and is unlikel y 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 in jection formations are extrao rdinarily unlikel y to occur.

F. Mechanical Integrity Testing (MIT) Requirements

The proposed rule suggests that “MIT requirement s for GS wells should be tailored to address the unique properties of CO2, speci fically its buoyancy and potentia l 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 inj ection pressure during injection, a factor that makes buoyancy virtually irrelevant as a driving force for upward migration through the injection well borehole during the op erational life of a GS well. Accordingly, there is no basis to suggest that the buoyancy of CO2 is a significant factor to c onsider in establishing mechanical integrity testing requirements for GS wells. Sim ilarly – as also previous ly discussed – CO2 is not corrosive and cannot be expected to cause s ubstantial corrosion problems for the injection well (including down-hole cement) unless the CO2 st ream 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 conclu sions. In fact, the Class II MIT requirements have been sufficient for CO2 in jection 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 co ntinuous injection a nd annulus pressure monitoring as a means to ensure “internal” mech anical 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 write r, subject only to a requirement that external

Carbon Sequestration Council (CCS C ontact Group) 24 bdday@bryancave.comDocket ID No. EPA–HQ–OW–2008–0390 December 23, 2008

mechanical integrity be demonstrated through a pproved MIT techniques at least once every five

years.

G. Testing and Monitoring Requirements

The preamble to the proposed rule indicates th at “EPA considers CO2 plume and associated pressure front monitoring to be necessary for ve rification of model predic tions.” 73 Fed. Reg. at 43514. This proposal unnecessarily undermines conf idence in the modeling demonstrations that can and should be relied upon to support determ inations that injected CO2 will not endanger USDWs. Modeling provides a conservative as sessment of the potential for movement of injected fluids in the subsurface, not a precise “pre diction” of actual fate a nd 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 e xperience 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 modeli ng. The additional monitoring re quirements proposed in the GS context go beyond what is required for Cla ss 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]on itoring 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, iden tify needed corrective actions, and target geochemical and surface monitoring activ ities.” 73 Fed. Reg. at 43514. Again, this is inconsistent with experience w ith 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 probl ematic in a variety of respects. They are expensive to install, create potential pathways for vertical fluid migra tion, 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 is olated “point measurements.” Monitor wells also have built-in confounding factors that include bot h 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. Be cause pressure fronts extend much further than injected fluid plume fronts during injection, pressu re 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 Dir ector to address particul ar 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 wast e injection does not commend the use

of monitor wells even in that context, and there is no justification to impose a more stringent an

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approach for the injection of CO 2 . Accordingly, we recommend th at the potential for gaining

useful information from monitor wells be care fully considered in de veloping an appropriate monitoring plan and that such wells be used on ly as justified by specific circumstances. (See Attachment A, 146.90(a).)

b. Geophysical Methods for Plume Tracking

As an alternative to monitor we lls, the proposed rule suggests th at it may be possible to use remote geophysical techniques for “plume track ing.” 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 expens ive and unnecessary quest.

2. Surface Air and Soil Gas Monitoring

The goal of any UIC program regula tions for GS should be to ensu re that injected CO2 streams

remain confined in the subsur face and do not endanger underground sources of drinking water. We are recommending sufficient re quirements to ensure that this goal is achieved. As EPA seems to recognize, surface air or soil gas mon itoring 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 CO 2 all the way to the surface, which – in the case of any properly-permitted GS project – would by defi nition be an extraordinarily low probability scenario. Accordingly, such requirements shoul d not be imposed, nor should regulators have discretion to impose them. If there is any serious concern that injected CO 2 might actually vent to the surface in a particular location, injection should not be permitted at that site in the first place. The regulations shoul d not suggest otherwise.

Carbon Sequestration Council (CCS C ontact Group) 26 bdday@bryancave.comDocket ID No. EPA–HQ–OW–2008–0390 December 23, 2008

Carbon Sequestration Council (CCS C ontact Group) 27 bdday@bryancave.com H. Financial Assurance

We support EPA’s flexible approa ch 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 instrume nts, regardless of wh ether those are current ly used for other classes of injection wells or in other EPA progr ams. 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 financ ial markets gain more experi ence with geologi c sequestration projects. EPA’s is wise to a void any artificial c onstraints on the development of potentially acceptable means of achieving financial assuranc e. 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 Sequestrati on 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.comDocket ID No. EPA–HQ–OW–2008–03901335843.7Attachment A: Comments and Recommendationsof the Carbon Sequestration Council on Specific Provisions of the Proposed GS RuleRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group CommentsPart 1441. The authority citation for part 144 continues to read asfollows:Authority: 42 U.S.C. 300f et seq.; Resource Conservationand Recovery Act, 42 U.S.C. 6901 et seq.No comment144.12. Section 144.1 is amended as follows:Adding new paragraph (f)(1)(viii); andb. Revising the first two sentences in paragraph (g)introductory text.* * * * *(f) * * *(1) * * *(viii) Subpart H of this part sets forth requirements forowners or operators of Class VI injection wells.* * * * *(g)Scope of the permit or rule requirement.TheUIC Permit Program regulates underground injections bysix classes of wells (see definition of ‘‘well injection,’’ §144.3). The six classes of wells are set forth in § 144.6. Allowners or operators of these injection wells must beauthorized either by permit or rule by the Director. * * *Support revision to include a sixth class of wells.144.6Add new paragraph (b)(4)(4) For enhanced recovery of oil or natural gaswhere geologic sequestration is occurring during or inconnection with enhanced recovery of oil or natural gasprovided(i) there is reasonable expectation of more thaninsignificant future production volumes or rates as a result ofcarbon dioxide injection and (ii)operating pressures are nohigher than reasonably necessary to produce such volumesor rates;EPA’s Proposal would continue to regulate and permitinjection of CO2 for EOR/EGR purposes as Class II injection“as long as any production is occurring.” EPA has asked forcomment on the merits of this approach “since owners oroperators of some Class II EOR/EGR wells may wish to usewells for the purposes of production and GS prior to the fieldbeing completely depleted.” 73 Fed. Reg. at 43502. Werecommend that the rules be clarified to provide morecertainty about the applicability of Class II requirementswhere GS of CO2 occurs in connection with EOR/EGRactivities. Specifically, the UIC rules should provide a “brightDecember 23, 2008Carbon Sequestration Council (CCS Contact Group)2 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsline” definition as to the applicable class of wells where CO2injection for EOR/EGR production and for GS occur intandem.The proposed language describing wells in classification(b)(4) establishes a “bright line”definition for wellsthat injectCO2 for EOR/EGR and GS and, consistent with EPA’s intent,should remain in Class II and be subject to the currentrequirements of Class II. We have also agreed that the wellsused for GS in oil and gas reservoirs that do not meet thecriteria of (b)(4) should be subject to additional requirements.This is the same recommendation as presented by the multistakeholder group, in which the Carbon SequestrationCouncil participated.144.63. Section 144.6 is amended as follows:Revising paragraph (e); andb. Adding new paragraph (f).* * * * *(e)Class V.Injection wells not included in Class I,II, III, IV, or VI. Specific typesof Class V injection wells aredescribed in § 144.81.(f)Class VI.Wells used for geologic sequestrationof carbon dioxide beneath the lowermost formationcontaining a USDW.Sections 144.6, and 146.5 – Classification of Wells:(f) Class VI. Wellsinjecting a carbon dioxide streamfor geologic sequestration except those wells described insubsection (b)(4) of this section or otherwise excluded fromthis Class.The changes to (b) and (f) are to recognize that EOR canhave a storage component, which is consistent with EPA’sintent as expressed in the preamble. It is widely recognizedthat CO2 based EOR can provide a significant earlyopportunity for carbon storage. As EPA correctly recognizes,CO2 EOR operations can have a significant storagecomponent through capillary trapping or other mechanisms.Operators experience supportsthis approach as they haveseen that between 1/3 to 1/2 of the injected CO2 in EORoperations is trapped within the receiving formation duringCO2 EOR operations. Following abandonment of EORoperations, assuming the CO2 not trapped in the receivingformation, has not been produced for use in another field,essentially all of the CO2 that has been injected can bepermanently stored.We recommend that all GS into basalts, coal seams, and saltdomes be conducted under Class V as experimental wellsinitially and then as commercialscale Class V wells/projects ifthe experimental projects demonstrate that these sites can besuitable for geological sequestration while preventingendangerment of USDWs.Keeping these wells under Class V would allow EPA and thestates to gain enough experience to develop suitablepermitting requirements for such wells and to tailor thoserequirements at both the pilot and commercial scales untilthe agencies are ready to adapt the Class VI regulations.December 23, 2008Carbon Sequestration Council (CCS Contact Group)3 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group CommentsThere should not be a blanket prohibition concerning injectionabove USDW’s or at specific depths. This requirement is notnecessary for the protectionof USDWs and would remove avast number of viable formations from consideration. Ithas been shown that it is possible to operate CO2 injectionwells in an EOR context without endangering USDWs that arelocated below the injection zone.An excellent example is theSalt Creek EOR project in Wyoming, which has a USDWbelow the injection zone. Under the proposed rule, there areother measures that would provide real assurance offormation integrity and require operators to demonstrate thattheir project will not endanger USDWs, making the lowermostUSDW restriction unnecessary.Instead, operators should beable to show adequate containment to prevent endangermentof USDWs both above and below the injection zone used forgeologic sequestration.144.15I4. Adding § 144.15 to read as follows.§ 144.15 Prohibition of non-experimental Class V wellsfor geologic sequestration.The construction, operation or maintenance of anynon-experimental Class V geologic sequestration well isprohibited.Delete this provision.This provision should be deleted if EPA does limit Class VIwells to injection below the lowermost USDW in the final ruleto allow Directors to selectively authorize GS in areas withUSDWs below the injection zone.144.185. Adding § 144.18 to read as follows.§ 144.18 Requirements for class VI wells.Owners or operators of Class VI wells must obtaina permit. Class VI wells are not authorized by rule to inject.Support the proposed language.Agree with EPA’s rationale.144.366. Section 144.36 is amended by revising the first twosentences in paragraph (a) to read as follows:§ 144.36 Duration of permits.(a) Permits for Class I and V wells shall be effectivefor a fixed term not to exceed10 years. UIC Permits forClass II, III and VI wells shall be issued for a period up tothe operating life of the facility. * * ** * * * *(a) Permits for Class I and V wells shall be effectivefor a fixed term not to exceed 10 yearsexcept for wells usedfor geologic sequestration. UIC Permits for Class IIandIIIand VIwells shall beissuedeffectivefor a period up to theoperating life of the facility.Permits for Class VI wells and forother wells used for geologic sequestration of CO2 streamsshall be effective for the period through site closure.Permits are necessary for geologic sequestration wellsthrough the end of the post closure monitoring phase, whichis consistent with the term site closure in the amendedrequirement.December 23, 2008Carbon Sequestration Council (CCS Contact Group)4 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments144.397. Section 144.39 is amended by revising thesecond sentence in paragraph (a) introductory text and byrevising the second sentence in paragraph (a)(3introductory text to read as follows:)These sections may require further revisions to provideconforming language.§ 144.39 Modification or revocation and reissuance ofpermits.* * * * *(a) * * * For Class I hazardous waste injectionwells, Class II, Class III or Class VI wells the following maybe causes for revocation and reissuance as well asmodification; and for all other wells the following may because for revocation or reissuance as well as modificationwhen the permittee requests or agrees. * * ** * * * *(3) * * * Permits other than for Class I hazardouswaste injection wells, Class II,Class III or Class VI wellsmay be modified during their terms for this cause only asfollows: * * ** * * * *The multi-stakeholder group has agreed that proposedlanguage describing wells in classification (b)(4) establishes a“bright line” definition for wells that inject CO2 for EOR/EGRand GS and, consistent with EPA’s intent, should remain inClass II and be subject to the current requirements of Class II.We have also agreed that the wells used for GS in oil and gasreservoirs that do not meet thecriteria of (b)(4) should besubject to additional requirements. We have tentativelydefined such wells as wells used “for geologic sequestrationin oil and gas formations and where the criteria of paragraph(b)(4) are not met.” But we have not yet attempted to definewhat specific requirements should apply to these wells. Weare committed to working toward agreement on thoserequirements (probably within a Class II context) andsubmitting the results of thateffort to EPA by February 28,2009 for your consideration.In addition, we recommend that all GS into basalts, coalseams, and salt domes be conducted under Class V asexperimental wells initially and then as commercial scaleClass V wells/projects if the experimental projectsdemonstrate that these sites can be suitable for geologicalsequestration while preventing endangerment of USDWs.144.518. Section 144.51 is amended by revising the firstsentence in paragraph (q)(1) and the first sentence inparagraph (q)(2) to read as follows:§ 144.51 Conditions applicable to all permits.* * * * *(q) * * *(1) The owner or operatorof a Class I, II, III or VIwell permitted under this part shall establish mechanicalintegrity prior to commencing injection or on a scheduledetermined by the Director.Thereafter the owner oroperator of Class I, II, and III wells must maintainmechanical integrity as defined in § 146.8 and the owner oroperator of Class VI wells must maintain mechanicalintegrity as defined in § 146.89 of this chapter. * * *(2) When the Director determines that a Class I, II,III or VI well lacks mechanicalintegrity pursuant to § 146.8(q) (1) The owner or operator of a Class I, II, III or VIwell permitted under this part shall establish mechanicalintegrity prior to commencing injection or on a scheduledetermined by the Director. Thereafter the owner or operatorof Class I, II, and III wells must maintain mechanical integrityas defined in §146.8 and the owner or operator of Class VIwells must maintain mechanical integrity as defined in§146.89 of this chapter.EPA may want to reconsider the use of the term “or” as thisimplies that an initial MITcan be optional based on Directorsdiscretion which contradicts 146.89 with respect to Class VIwells. Alternatively, the two provisions can be read togetherto require an initial MIT and to give the Director limiteddiscretion to allow the scheduling of the initial MIT after someinjection has occurred, such as may be required during initialtesting of the well and injection zone.December 23, 2008Carbon Sequestration Council (CCS Contact Group)5 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsor § 146.89 for Class VI of this chapter, he/she shall givewritten notice of his/ her determination to the owner oroperator. * * ** * * * *144.529. Section 144.52 is amended by revisingparagraph (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 injectionproject which lacks mechanicalintegrity shall include, and for any Class V well may include,a condition prohibiting injection operations until thepermittee shows to the satisfaction of the Director under §146.08 or § 146.89 for Class VI that the well hasmechanical integrity.* * * * *Support the proposed language.Agree with EPA’s rationale.144.55§ 144.55 Corrective action.(a)Coverage.Applicants for Class I, II, (other thanexisting), III or VI injection well permits shall identify thelocation of all known wells within the injection well’s area ofreview which penetrate the injection zone, or in the case ofClass II wells operating over the fracture pressure of theinjection formation, all known wells within the area of reviewpenetrating formations affected bythe increase in pressure.Applicants for Class VI shall perform corrective action asspecified in § 146.84.* * ** * * * *Support the proposed language.Agree with EPA’s rationale.144.8011. Section 144.80 is amended by revising thefirst sentence in paragraph (e) and by addingparagraph (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 fluids:......(2) forenhanced recovery of oil or natural gas; (3)For storage ofhydrocarbons.... and(4) For enhanced recovery of oil or natural gaswhere geologic sequestration is occurring during or inconnection with enhanced recovery of oil or natural gasEPA’s Proposal would continue to regulate and permitinjection of CO2 for EOR/EGR purposes as Class II injection“as long as any production is occurring.” EPA has asked forcomment on the merits of this approach “since owners oroperators of some Class II EOR/EGR wells may wish to usewells for the purposes of production and GS prior to the fieldbeing completely depleted.” 73 Fed. Reg. at 43502. Werecommend that the rules be clarified to provide moreDecember 23, 2008Carbon Sequestration Council (CCS Contact Group)6 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsprovided(i) there is reasonable expectation of more thaninsignificant future production volumes or rates as a result ofcarbon dioxide injection and (ii)operating pressures are nohigher than reasonably necessary to produce such volumesor rates;certainty about the applicability of Class II requirementswhere GS of CO2 occurs in connection with EOR/EGRactivities. Specifically, the UIC rules should provide a “brightline” definition as to the applicable class of wells where CO2injection for EOR/EGR production and for GS occur intandem.The proposed language describing wells in classification(b)(4) establishes a “bright line”definition for wellsthat injectCO2 for EOR/EGR and GS and, consistent with EPA’s intent,should remain in Class II and be subject to the currentrequirements of Class II. We have also agreed that the wellsused for GS in oil and gas reservoirs that do not meet thecriteria of (b)(4) should be subject to additional requirements.This is the same recommendation as presented by the multistakeholder group, in which the Carbon SequestrationCouncil participated.(e)Class V. Injection wells not included inClass I, II, III, IV or VI. * * *Support the proposed language.Agree with EPA’s rationale.(f)Class VI. Wells used for geologicsequestration of carbon dioxide.(f) Class VI. Wellsinjecting a carbon dioxide streamfor geologic sequestration except those wells described insubsection (b)(4) of this section or otherwise excluded fromthis Class.The changes to (b) and (f) are to recognize that EOR canhave a storage component, which is consistent with EPA’sintent as expressed in the preamble. It is widely recognizedthat CO2 based EOR can provide a significant earlyopportunity for carbon storage. As EPA correctly recognizes,CO2 EOR operations can have a significant storagecomponent through capillary trapping or other mechanisms.Operators experience supportsthis approach as they haveseen that between 1/3 to 1/2 of the injected CO2 in EORoperations is trapped within the receiving formation duringCO2 EOR operations. Following abandonment of EORoperations, assuming the CO2 not trapped in the receivingformation, has not been produced for use in another field,essentially all of the CO2 that has been injected can bepermanently stored.We recommend that all GS into basalts, coal seams, and saltdomes be conducted under Class V as experimental wellsinitially and then as commercialscale Class V wells/projects ifDecember 23, 2008Carbon Sequestration Council (CCS Contact Group)7 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsthe experimental projects demonstrate that these sites can besuitable for geological sequestration while preventingendangerment of USDWs.Keeping these wells under Class V would allow EPA and thestates to gain enough experience to develop suitablepermitting requirements for such wells and to tailor thoserequirements at both the pilot and commercial scales untilthe agencies are ready to adapt the Class VI regulations.Additionally, there should not be a blanket prohibitionconcerning injection above USDW’s or at specific depths.This requirement is not necessary for the protection ofUSDWs and would remove a vast number of viableformations from consideration. Industry has shown that it canoperate CO2 injection wells in an EOR context withoutendangering USDWs that are located below the injectionzone. An excellent example is the Salt Creek EOR project inWyoming, which has a USDW below the injection zone.Moreover, under the proposed rule, there are other measuresthat would provide real assurance of formation integrity andrequire operators to demonstrate that their project will notendanger USDWs, making the lowermost USDW restrictionunnecessary. Instead, operators should be able to showadequate containment to prevent endangerment of USDWsboth above and below the injection zone used for geologicsequestration.Part 14612. The authority citation for part 146 continuesto read as follows:Authority: Safe Drinking Water Act 42, U.S.C.300f et seq.; Resource Conservation and Recovery Act,42 U.S.C. 6901et seq.Support the proposed language.Agree with EPA’s rationale.146.513. Section 146.5 is amended as follows:(b) Class II. Classification of Wells:(b) Class II. Wells which inject fluids:......(2) forenhanced recovery of oil or natural gas; (3)For storage ofhydrocarbons.... and(4) For enhanced recovery of oil or natural gaswhere geologic sequestration is occurring during or inconnection with enhanced recovery of oil or natural gasprovided(i) there is reasonable expectation of more thanEPA’s Proposal would continue to regulate and permitinjection of CO2 for EOR/EGR purposes as Class II injection“as long as any production is occurring.” EPA has asked forcomment on the merits of this approach “since owners oroperators of some Class II EOR/EGR wells may wish to usewells for the purposes of production and GS prior to the fieldbeing completely depleted.” 73 Fed. Reg. at 43502. Werecommend that the rules be clarified to provide morecertainty about the applicability of Class II requirementsDecember 23, 2008Carbon Sequestration Council (CCS Contact Group)8 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsinsignificant future production volumes or rates as a result ofcarbon dioxide injection and (ii)operating pressures are nohigher than reasonably necessary to produce such volumesor rates;where GS of CO2 occurs in connection with EOR/EGRactivities. Specifically, the UIC rules should provide a “brightline” definition as to the applicable class of wells where CO2injection for EOR/EGR production and for GS occur intandem.The proposed language describing wells in classification(b)(4) establishes a “bright line”definition for wellsthat injectCO2 for EOR/EGR and GS and, consistent with EPA’s intent,should remain in Class II and be subject to the currentrequirements of Class II. We have also agreed that the wellsused for GS in oil and gas reservoirs that do not meet thecriteria of (b)(4) should be subject to additional requirements.This is the same recommendation as presented by the multistakeholder group, in which the Carbon SequestrationCouncil participated.a. Revising the first sentence in paragraph (e)introductory text; and(e)Class V. Injection wells not included inClass I, II, III, IV or VI. * * *Support the proposed language.Agree with EPA’s rationale.b. Adding paragraph (f).(f) Class VI. Wells used for geologic sequestration ofcarbon dioxide beneath the lowermost formationcontaining an underground source of drinking water(USDW).(f) Class VI. Wellsinjecting a carbon dioxide streamfor geologic sequestration except those wells described insubsection (b)(4) of this section or otherwise excluded fromthis Class.The changes to (b) and (f) are to recognize that EOR canhave a storage component, which is consistent with EPA’sintent as expressed in the preamble. It is widely recognizedthat CO2 based EOR can provide a significant earlyopportunity for carbon storage. As EPA correctly recognizes,CO2 EOR operations can have a significant storagecomponent through capillary trapping or other mechanisms.Operators experience supportsthis approach as they haveseen that between 1/3 to 1/2 of the injected CO2 in EORoperations is trapped within the receiving formation duringCO2 EOR operations. Following abandonment of EORoperations, assuming the CO2 not trapped in the receivingformation, has not been produced for use in another field,essentially all of the CO2 that has been injected can bepermanently stored.We recommend that all GS into basalts, coal seams, and saltdomes be conducted under Class V as experimental wellsinitially and then as commercialscale Class V wells/projects ifDecember 23, 2008Carbon Sequestration Council (CCS Contact Group)9 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsthe experimental projects demonstrate that these sites can besuitable for geological sequestration while preventingendangerment of USDWs.Keeping these wells under Class V would allow EPA and thestates to gain enough experience to develop suitablepermitting requirements for such wells and to tailor thoserequirements at both the pilot and commercial scales untilthe agencies are ready to adapt the Class VI regulations.Additionally, there should not be a blanket prohibitionconcerning injection above USDW’s or at specific depths.This requirement is not necessary for the protection ofUSDWs and would remove a vast number of viableformations from consideration. Industry has shown that it canoperate CO2 injection wells in an EOR context withoutendangering USDWs that are located below the injectionzone. An excellent example is the Salt Creek EOR project inWyoming, which has a USDW below the injection zone.Moreover, under the proposed rule, there are other measuresthat would provide real assurance of formation integrity andrequire operators to demonstrate that their project will notendanger USDWs, making the lowermost USDW restrictionunnecessary. Instead, operators should be able to showadequate containment to prevent endangerment of USDWsboth above and below the injection zone used for geologicsequestration.Part 146Subpart H14. Subpart H is added to read as follows:Subpart H—Criteria and Standards Applicable to ClassVI WellsSec.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 injectionwell operation.Support the proposed language.Agree with EPA’s rationale.December 23, 2008Carbon Sequestration Council (CCS Contact Group)10 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments146.81Applicability.(a) This subpart establishes criteria and standardsfor underground injection control programs to regulateClass VI carbon dioxide geologic sequestration injectionwells.These sections may require further revisions to provideconforming language.The multi-stakeholder group has agreed that proposedlanguage describing wells in classification (b)(4) establishes a“bright line” definition for wells that inject CO2 for EOR/EGRand GS and, consistent with EPA’s intent, should remain inClass II and be subject to the current requirements of Class II.We have also agreed that the wells used for GS in oil and gasreservoirs that do not meet thecriteria of (b)(4) should besubject to additional requirements. We have tentativelydefined such wells as wells used “for geologic sequestrationin oil and gas fo rmations and where the criteria of paragraph(b)(4) are not met.” But we have not yet attempted to definewhat specific requirements should apply to these wells. Weare committed to working toward agreement on thoserequirements (probably within a Class II context) andsubmitting the results of thateffort to EPA by February 28,2009 for your consideration.In addition, we recommend that all GS into basalts, coalseams, and salt domes be conducted under Class V asexperimental wells initially and then as commercial scaleClass V wells/projects if the experimental projectsdemonstrate that these sites can be suitable for geologicalsequestration while preventing endangerment of USDWs.(b) This subpart appliesto wells used to injectcarbon dioxide specifically for the purpose of geologicsequestration, i.e., the long-term containment of a gaseous,liquid or supercritical carbon dioxide stream in subsurfacegeologic formations.(b) This subpart applies to wells used to injectcarbon dioxideexclusivelyfor the purpose of geologicsequestration, i.e., the long-term containment of agaseous,liquid or supercriticalcarbon dioxide stream in subsurfacegeologic formationsother than oil or gas reservoirs, coalseams, basalts, or salt caverns.See 144.6 and the note immediately above about therequirement for conforming language.Deleted “gaseous, liquid or supercritical” because it wasadded to the definition of CO2 stream.(c) This subpart applies to owners and operators ofpermit or rule-authorized Class I industrial, Class II, orClass V experimental carbon dioxide injection projects whoseek to apply for a Class VI geologic sequestration permitfor their well or wells. If the Director determines thatUSDWs will not be endangered, such wells are exempt, atthe Director’s discretion,from the casing and cementingrequirements at §§ 146.86(b) and 146.87(a)(1) through (3).(c) This subpart applies to owners and operators ofpermit or rule-authorized Class I industrial, Class IIwhichhave ceased and will no longer be used for enhancedrecovery of oil or natural gas, or Class V experimental carbondioxide injection projects who seek to apply for a Class VIgeologic sequestration permit for their well or wells. If theDirector determines that USDWs will not be endangered,such wells are exempt, at the Director’s discretion, from thecasing and cementing requirements at §§ 146.86(b) and146.87(a)(1) through (3).Class VI requirements of Subpart Hof this Part. Wells constructed inaccordance with the Class IIrequirements of § 146.22 and used in CO2 service and thatFor first part, see 144.6 and the note above about therequirement for conforming language.Added language for transition of Class II wells to Class VIoperations. These wells should be allowed based on theirhistory of sound performance under the Class II program asdemonstrated by MIT results. The language also allows theDirector to exercise discretion to exempt other Class VIrequirements.December 23, 2008Carbon Sequestration Council (CCS Contact Group)11 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentshave demonstrated MIT are exemptfrom the requirements at§§146.86 and 146.87.146.81(d) Definitions(d)Definitions.The following definitions apply tothis subpart. To the extentthat these definitions conflictwith those in § 146.3 these definitions govern:Area of reviewmeans the region surrounding the geologicsequestration project that may be impacted by the injectionactivity. The area of review is based on computationalmodeling that accounts for the physical and chemicalproperties of all phases ofthe injected carbon dioxidestream.(d)Definitions.The following definitions apply to thissubpart. To the extent that these definitions conflict withthose in § 146.3 these definitions govern:Area of review means theregion surrounding the geologicsequestration project that may be impacted by the injectionactivity. Thearea of review is based on computationalmodeling that accounts for the physical and chemicalproperties of all phases of the injected carbon dioxidestream.subsurface three-dimensional extent of the carbondioxide plume, associated pressure front, as well as theoverlying formations and surface area above that delineatedregion.Defining the AOR based on the extent of the CO2 plume andits associated pressure front isa more direct approach, ratherthan the approach offered by the EPA.Carbon dioxide plumemeans the underground extent, inthree dimensions, of an injected carbon dioxide stream.Carbon dioxide streammeans carbon dioxide that has beencaptured from an emission source (e.g., a power plant),plus incidental associated substances derived from thesource materials and the capture process, and anysubstances added to the stream to enable or improve theinjection process. This subpart does not apply to anycarbon dioxide stream thatmeets the definition of ahazardous waste under 40 CFR part 261.Carbon dioxide plumemeans the underground extent, inthree dimensions, of an injected carbon dioxide stream.Carbon dioxide streammeans carbon dioxide, in anyphysical state or form,and any associatedsubstancesderived from thethat has been captured from an emissionsource(e.g., a power plant), plus incidental associatedsubstances derived from the source materials and thecapture process, and anyor its processing, andsubstancesadded to enable or improve the injection process. Thissubpart does not apply to any carbon dioxide stream thatmeets the definition of a hazardous waste under 40 CFR part261.Source of CO2 is not an issuein the context of defining theCO2 stream. The rule applies to the injection of CO2 andshould not address the origins ofthe materials since that isbeyond the scope of this regulation. Original text would haveprecluded injection of CO2 from some sources.Confining zonemeans a geologic formation, group offormations, or part of a formation stratigraphically overlyingthe injection zone that acts as a barrier to fluid movement.Confining zonemeans a geological formation, group offormations, or part of a formationthat is capable of limitingfluid movement from an injection zone.The current UIC program definition of confining zone ispreferable to the proposed definition. There are no specialcircumstances for CO2 streamsthat warrant a change. Inaddition, the word “above” should be changed to “from” toaccommodate situations where USDWs may be beneath aswell as above the injection zone.December 23, 2008Carbon Sequestration Council (CCS Contact Group)12 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group CommentsCorrective actionmeans the use of Director approvedmethods to assure that wells within the area of review donot serve as conduits for the movement of fluids intounderground sources of drinking water (USDW).Support the proposed language.Agree with EPA’s rationale.Geologic sequestrationmeans the long-term containment ofa gaseous, liquid or supercritical carbon dioxide stream insubsurface geologic formations. This term does not applyto its capture or transport.Geologic sequestrationmeans the long-term containment ofagaseous, liquid or supercriticalcarbon dioxide stream insubsurface geologic formations. This term does not apply toits capture or transport.Added to definition of carbon dioxide stream, so not neededhere.Geologic sequestration projectmeans an injection well orwells used to emplace a carbon dioxide stream beneath thelowermost formation containing a USDW. It includes thesubsurface three-dimensional extent of the carbon dioxideplume, associated pressure front, and displaced brine, aswell as the surface area above that delineated region.Geologic sequestration projectmeans an injection well orwells used to emplace a carbon dioxide streambeneath thelowermost formation containing a USDWinto an injectionzone exclusively for the purposeof geologic sequestration.Itincludes the subsurface three-dimensional extent of thecarbon dioxide plume, associated pressure front, anddisplaced brine, as well asthe surface area above thatdelineated region.There should not be a blanket prohibition concerning injectionabove USDW’s or at specific depths. This requirement is notnecessary for the protectionof USDWs and would remove avast number of viable formations from consideration.Industry has shown that it can operate CO2 injection wells inan EOR context without endangering USDWs that are locatedbelow the injection zone. An excellent example is the SaltCreek EOR project in Wyoming, which has a USDW belowthe injection zone. Moreover, under the proposed rule, thereare other measures that would provide real assurance offormation integrity and require operators to demonstrate thattheir project will not endanger USDWs, making the lowermostUSDW restriction unnecessary.Injection zonemeans a geologic formation, group offormations, or part of a formation that is of sufficient a realextent, thickness, porosity, and permeability to receivecarbon dioxide through a well or wells associated with ageologic sequestration project..Injection zonemeans a geologic formation, group offormations, or part of a formationthat is of sufficient arealextent, thickness, porosity,and permeability to receivecarbon dioxidereceiving fluidsthrough a wellor wellsassociated with a geologicsequestration projectExisting definition in the CFR is sufficient and does not needto be changed. Furthermore, adding the sufficiencyrequirement is not a definitional issue and should be dealtwith elsewhere.Post-injection site caremeans appropriate monitoring andother actions (including corrective action) needed followingcessation of injection toassure that USDWs are notendangered as required under § 146.93Post-injection site caremeansappropriatemonitoring andother actions (including corrective action)neededfollowingcessation of injectionto assure that USDWs are notendangered, as required under §146.93.Deleted “appropriate” because the definition of it is not clear.Deleted USDW phrase because it is incorporated in 146requirements.December 23, 2008Carbon Sequestration Council (CCS Contact Group)13 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group CommentsPressure frontmeans the zone of elevated pressure that iscreated by the injection of carbon dioxide into thesubsurface. For the purposes of this subpart, the pressurefront of a carbon dioxide plumerefers to a zone where thereis a pressure differential sufficient to cause the movementof injected fluids or formation fluids into a USDW.Pressure frontmeans the zone of elevated pressure that iscreated by the injection of the carbon dioxidestreaminto thesubsurface,For the purposes of this subpart, the pressurefront of a carbon dioxide plume refers to a zonewhere thereis a pressure differential sufficient to cause movement ofinjected fluidsthe carbon dioxide streamor formation fluidsfrom the injection zoneinto a USDW.Clarification.Site closurethe point/time, as determined by the Directorfollowing the requirements under § 146.93, at which theowner or operator of a GS site is released from postinjection site careresponsibilities.Site closuremeansthe point/time, as determined by theDirector following the requirements under §146.93, at whichthe owner or operator of a GSsiteprojectis released frompost-injection site care responsibilities.“GS project” is consistent with other definitions.Transmissive fault or fracturemeans a fault or fracture thathas sufficient permeability and vertical extent to allow fluidsto move between formations.Transmissive fault or fracturemeans a fault or fracture thathas sufficient permeability and vertical extent to allow fluidsto movebetween formationsbeyond the confining zone.The term "between formations" is inaccurate since there canbe multiple formations within an injection zone. The criticalfactor for transmissivity is movement of injected or displacedfluids beyond the confining zone.146.82Required Class VI permit informationThis section sets forth the information which the owner oroperator must submit to the Director in order to bepermitted as a Class VI well. The application for a permitfor construction and operation of a Class VI well mustinclude the following:Support the proposed language.Agree with EPA’s rationale.(a) Information required in 40 CFR 144.31(e)(1)through (6);Support the proposed language.Agree with EPA’s rationale.146.82(a)(b) A map showing the injection well(s) for which apermit is sought and the applicable area of review. Withinthe area of review, the map must show the number, orname and location of all injection wells, producing wells,abandoned wells, plugged wells or dry holes, deepstratigraphic boreholes, Stateor EPA approved subsurfacecleanup sites, surface bodies of water, springs, mines(surface and subsurface), quarries, water wells and otherpertinent surface features including structures intended forhuman occupancy and roads. The map should also showfaults, if known or suspected. Only information of public(b) Asurfacemap showing theproposed locationsforthe injection well(s) for which a permit is sought and theapplicable area of review. Within the area of review, the mapmust show the number, or name and location of allknowninjection wells, producing wells, abandoned wells, pluggedwells or dry holes, deep stratigraphic boreholes, State orEPA approved subsurface cleanup sites,surface bodies ofwater, springs, mines (surface and subsurface), quarries,water wells and other pertinent surface features includingstructures intended for human occupancy and roads.Themap should also show faults, if known or suspected.OnlyFaults are not shown on maps unless there is a surfaceexpression of the fault. Also, faults are detailed in (d) belowand this language appears redundant.The word “known” needs to be added to remove anyimplication that an applicant has to conduct studies todetermine the location of wells that are not currentlydocumented in some fashion.December 23, 2008Carbon Sequestration Council (CCS Contact Group)14 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsrecord is required to be included on this map;information of public record is required to be included on thismap;(c) The area of review based on modeling, usingdata obtained during logging and testing of the well and theformation as required by paragraphs (l), (r), and (s) of thissection;(c)A map delineatingthe area of review basedonuponmodeling, usingall availabledataincluding dataobtained during logging and testing ofthe well andtheformation as required by paragraphs (l), (r), and (s) of thissectionany wells in the area of reviewThis appears to be related to a condition where a well isalready drilled. This does not align with requestinginformation to receive a permit.(d) Information on the geologic structure andhydrogeologic properties of the proposed storage site andoverlying formations, including:(1) Maps and cross sections of the area of review;(2) Location, orientation, and properties of known orsuspected faults and fractures that may transect theconfining zone(s) in the area of review and a determinationthat they would not interfere with containment;(d)Knowninformation on the geologic structure andhydrogeologicreservoirproperties of the proposed storagesite and overlying formations, including:(1)Isopachmapsandof the proposed injection andconfining zone(s), a structural contour map hung on the topof the proposed injection zone, and at least two geologiccross sections of the area of reviewshowing the geologicformations from the surface to total depth.(2) Location, orientation, and properties of known orsuspectedsubsurfacefaultsand fracturesthat may transectthe confining zone(s) in the area of review and adetermination that they would notinterfere with containment;If the information is not known, it cannot be reported.“Reservoir” and changes to (1) and (2) are technicalcorrections.Fractures generally can’t be identified until a well is drilledand evaluated. Even then, only fractures in the immediatevicinity of the wellbore can be identified.(3) Information on seismic history including thepresence and depth of seismic sources and a determinationthat the seismicity would notinterfere with containment;(4) Data on the depth, areal extent, thickness,mineralogy, porosity, permeabilityand capillary pressure ofthe injection and confining zone(s); including geology/facieschanges based on field data which may include geologiccores, outcrop data, seismicsurveys, well logs, and namesand lithologic descriptions;(5) Geomechanical information on fractures, stress,ductility, rock strength, and in situ fluid pressures within theconfining zone; and(3) Information on seismic historythat have affectedthe proposed area of review,including knowledge of previousseismic events,including the presence and depth of seismicsources and a determination that the seismicity would notinterfere with containment;(4)Datasufficient to demonstrate the effectivenessof the injection and confining zone(s), including data on thedepth, areal extent, thickness,mineralogy, porosity, verticalpermeability reservoir pressure and of the injection andconfining zone(s) within the area of review; includinggeologic changes based on field data which may includegeologic cores, outcrop data,seismic surveys, well logs,capillary pressure tests and namesand lithologicdescriptions;(5)Knowngeomechanical information onfractures,stress, ductility, rock strength, and in situ fluid pressureswithinthe confining zone(s)within the area of review; andInformation on seismic history should have some degree ofrelevance to the project.Capillary pressure is too hardto 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 difficultto core the whole of the confining and injection zones.Rewording keeps the usefulness of capillarypressure in theprovision without making it a mandatory use.Clarification.December 23, 2008Carbon Sequestration Council (CCS Contact Group)15 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(6) Geologic and topographic maps and crosssections illustrating regional geology, hydrogeology, and thegeologic structure of the local area.Delete item 6 because this issue is covered under othersections such as (b).146.82(e)(e) A tabulation of all wells within the area of reviewwhich penetrate the injection or confining zone(s). Suchdata must include a description of each well’s type,construction, date drilled, location, depth, record of pluggingand/ or completion, and any additional information theDirector may require;(e)Atabulationrecordof allwellsartificialpenetrationswithin the area of reviewwhich penetratethatreachthe injection or confining zone(s). Such dataasavailable in the public recordmust include a description ofeachwell’spenetration’stype, construction, date drilled,location, depth, record of plugging and/ or completion, andany additional information the Director may require;“Artificial penetrations” isa more inclusive term.(f) Maps and stratigraphic cross sections indicatingthe general vertical and lateral limits of all USDWs, waterwells and springs within the area of review, their positionsrelative to the injection zone(s) and the direction of watermovement, where known;(f)Maps and stratigraphic cross sections indicatingthe general vertical and lateral limits of all USDWs, waterwells and springs within the area of review, their positionsrelative to the injection zone(s) and the direction of watermovement, where known;Potentiometric (water level)surface map(s) of existing aquifers being utilized as privateor public water supplies and the direction of groundwater flowin these aquifers within the area of review. At least twogeologic cross sections showing the thickness and generalvertical and lateral limits of all USDWs within the area ofreview.This revision more accurately identifies the information that isneeded and should be considered for permitting.(g) Baseline geochemical data on subsurfaceformations, including all USDWs in the area of review;(g)Baseline geochemical data on subsurfaceformations, including all USDWs in the area of reviewCompilation of available geochemical data on the proposedinjection zone and nearest porous and permeable formationabove the confining zone.Limits the data to be submitted to available information and tothe injection zone and the zone immediately above theconfining zone which are the zones most likely to bemonitored for potential CO2 leakage.(h) Proposed operating data:(1) Average and maximum daily rate and volume ofthe 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 physicalcharacteristics of the carbon dioxide stream;(h) Proposed operating data:(1) Average and maximum dailyinjectionrate andvolume of the carbon dioxide stream;(2) Average and maximumsurfaceinjectionpressure;(3) The source of the carbon dioxide stream; and(4) An analysis of the chemical and physicalcharacteristics of the carbon dioxide stream;ClarificationsTechnical clarifications.December 23, 2008Carbon Sequestratio unrfvanvoorhees@bryancave.comn Co cil (CCS Contact Group)16Rule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments146.82(i) The compatibility of the carbon dioxide streamwith fluids in the injection zone and minerals in both theinjection and the confining zone(s), based on the results ofthe formation testing program, and with the materials usedto construct the well;Support the proposed language.Agree with EPA’s rationale.146.82(j) Proposed formation testing program to obtain ananalysis of the chemical and physical characteristics of theinjection zone and confining zone;Support the proposed language.Agree with EPA’s rationale.146.82(k) Proposed stimulation program and adetermination that stimulation will not interfere withcontainment;(k) Proposed stimulation program and adetermination that stimulation will not compromisecontainment;“Interfere” is too ambiguous and should be replaced by“compromise” which limits concerns to situations wherecontainment may be lost.146.82(l) The results of theformation testing program asrequired in paragraph (j) of this section;(m) Proposed procedureto outline steps necessaryto conduct injection operation;(n) Schematic or other appropriate drawings of thesurface and subsurface construction details of the well;(o) Injection well construction procedures that meetthe requirements of § 146.86;(l) The results of the formation testing program asrequired in paragraph (j) of this section;(m) Proposed procedure to outline steps necessary toconduct injection operation;(n)A wellboreschematicor other appropriatedrawings of the surface andof the subsurface constructiondetailsof the welland surface wellhead construction.(o) Injection well construction procedures that meetthe requirements of § 146.86;(n) Technical clarification.(p) Proposed area of review and corrective actionplan that meets the requirements under § 146.84;Support the proposed language.Agree with EPA’s rationale(q) The status of corrective action on wells in thearea of review;(r) All available logging and testing program data onthe well required by § 146.87;(s) A demonstration of mechanical integrity(q)TheAnystatus of corrective action on wells inthe area of review;(r) All available logging and testing program data onthe well required by § 146.87;(s) The proposed demonstration method forClarifies that wellsnot needing correctiveaction will not havea corrective action status.December 23, 2008Carbon Sequestration Council (CCS Contact Group)17 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentspursuant to§ 146.89;(t) A demonstration, satisfactory to the Director, thatthe applicant has met the financial responsibilityrequirements under § 146.85;mechanical integrity pursuant to(t) A demonstration, satisfactory to the Director, thatthe applicant has met the financial responsibilityrequirements under § 146.85;146.82(u)(u) Proposed testing and monitoring plan requiredby§ 146.90;(v) Proposed injection well plugging plan requiredby§ 146.92(b);(w) Proposed post-injection site care and siteclosure plan required by § 146.93(a);(x) Proposed emergency and remedial responseplan required by § 146.94; and(y) Any other informationrequested by the Director.(u) Proposed testing and monitoring plan required by§ 146.90;(v) Proposed injection and monitoring well(s)plugging plan required by § 146.92(b);(w) Proposed post-injection site care and site closureplan required by § 146.93(a);(x) Proposed emergency and remedial responseplan required by § 146.94; and(y) Any other informationrequested by the Director.146.833. Minimum criteria for siting(a) Owners or operators of Class VI wells mustdemonstrate to the satisfaction ofthe Director that the wellswill be sited in areas with asuitable geologic system. Thegeologic system must be comprised of:(1) An injection zone of sufficient areal extent,thickness, porosity, and permeability to receive the totalanticipated volume of the carbon dioxide stream;Support the proposed language.Agree with EPA’s rationale.(2) A confining zone(s) that is free of transmissivefaults or fractures and of sufficient areal extent and integrityto contain the injected carbondioxide stream and displacedformation fluids and allow injection at proposed maximumpressures and volumes without initiating or propagatingfractures in the confining zone(s); and(2) A confining zone(s) that islaterally continuousandfree ofknown transecting,transmissive faultsorfracturesand of sufficient areal extent and integrity to containthe injected carbon dioxide stream and displaced formationfluids and allow injection at proposed maximum pressuresand volumes without initiating or propagating fractures in theconfining zone(s); andover an area sufficient to prevent themovement of injected or displaced fluids into a USDW;The proposed clarification keeps the emphasis on the nonendangerment of USDWs and limits the requirements to thatwhich is known or can be readily determined.December 23, 2008Carbon Sequestration Council (CCS Contact Group)18 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(b) At the Director’s discretion, owners or operatorsof Class VI wells must identify and characterize additionalzones that will impede vertical fluid movement, are free offaults and fractures that may interfere with containment,allow for pressure dissipation, and provide additionalopportunities for monitoring, mitigation and remediation.(b) At the Director’sdiscretion, owners or operatorsof Class VI wells must identify and characterize additionalzones that will impede vertical fluid movement, are free offaults and fractures that may interfere with containment,allow for pressure dissipation, and provide additionalopportunities for monitoring, mitigation and remediation.This paragraph creates a presumption that additionalconfining zones WILL be required. It is also redundant giventhe previous sections. Providing for a confining zone thatmeets the requirements should be sufficient. Any furtheridentification of confining zones would potentially eliminatezones useful for future geologic sequestration.146.84146.84. Area of review and corrective action(a) The area of review is the region surrounding thegeologic sequestration project that may be impacted by theinjection activity. The area of review is based oncomputational modeling that accounts for the physical andchemical properties of all phases of the injected carbondioxide stream.(a) The area of review isthe region surrounding thegeologic sequestration project that may be impacted by theinjection activity. The area of review isbased oncomputational modeling that accounts for the physical andchemical properties of all phases of theinjected carbondioxide stream.the subsurface three-dimensional extent ofthe carbon dioxide plume, associated pressure front, as wellas the overlying formations and surface area above thatdelineated region.Edits make this provision consistent with the definition of“Area of Review”, which was revised.(b) The owner or operator of a Class VI well mustprepare, maintain, and comply with a plan to delineate thearea of review for a proposed geologic sequestrationproject, periodically reevaluate the delineation, and performcorrective action that meets the requirements of this sectionand is acceptable to the Director. As a part of the permitapplication for approval by the Director, the owner oroperator must submit an area of review and correctiveaction plan that includes the following information:(1) The method for delineating the area of reviewthat meets the requirements ofparagraph (c) of this section,including the model to be used, assumptions that will bemade, and the site characterization data on which themodel will be based;(b) The owner or operator of a Class VI well mustprepare, maintain, and comply with a plan to delineate thearea of review for a proposed geologic sequestration project,periodicallyreevaluate the delineation, and performcorrective action that meets the requirements of this sectionand isin a manner and at a frequencyacceptable to theDirector. As a part of the permit application,for approval bythe Directorthe owner or operator must submit an area ofreview and corrective action plan that includes the followinginformation:(1) The method for delineating the area of reviewthat meets the requirements of paragraph (c) of this section,including the model to be used, assumptions that will bemade, and the site characterization data on which the modelwill be based;Clarification.146.84(b)(2)(2) A description of:(i) The minimum fixed frequency, not to exceed 10years, the owner or operatorproposes to reevaluate thearea of review;(ii) The monitoring and operational conditions thatwould warrant a reevaluation of the area of review prior tothe next scheduled reevaluation as determined by theminimum fixed frequency established in paragraph (b)(2)(i)(2) A description of:(i) The minimum fixed frequency, not to exceed 10 years, theowner or operator proposes to reevaluate the area of review;(ii) The monitoring and operational conditions thatwould warrant a reevaluation of the area of review prior tothe next scheduled reevaluation as determined by theminimum fixed frequency established in paragraph (b)(2)(i) ofthis section.These provisions in (i) and (ii)are rendered unnecessary bythe revisions to section 146.84(b).December 23, 2008Carbon Sequestration Council (CCS Contact Group)19 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsof this section.(iii) How monitoring and operational data (e.g.,injection rate and pressure)will be used to inform an areaof review reevaluation; and(iii)(i)How monitoring and operational data (e.g.,injection rate and pressure) will be used to inform an area ofreview reevaluation; andAgree with EPA’s rationale.(iv) How corrective actionwill be conducted to meetthe requirements of paragraph (d) of this section, includingwhat corrective action will beperformed prior to injectionand what, if any, portions of the area of review will havecorrective action addressed on a phased basis and how thephasing will be determined; how corrective action will beadjusted if there are changes in the area of review; and howsite access will be guaranteed for future corrective action.(ivii) How corrective action will be conducted tomeet the requirements of paragraph (d) of this section,including what corrective action will be performed prior toinjection and what, if any, portions of the area of review willhave corrective action addressed on a phased basis and howthe phasing will be determined; how corrective action will beadjusted if there are changes in the area of review; and howsite access will beguaranteedarrangedfor future correctiveaction.Future access cannot be guaranteed for an area in advancethat may not even be within the boundaries of the AOR/project.146.84(c)(c) Owners or operators of Class VI wells mustperform the following actions to delineate the area ofreview, identify all wells that require corrective action, andperform corrective action on those wells:(1) Predict, using computational modeling, theprojected lateral and verticalmigration of the carbon dioxideplume and formation fluids in the subsurface from thecommencement of injection activities until the plumemovement ceases, pressure differentials sufficient to causethe movement of injected fluids or formation fluids into aUSDW are no longer present, or after a fixed time period asdetermined by the Director. The model must:(c) Owners or operatorsof Class VI wells mustperform the following actions to delineate the area of review,identify all wells that require corrective action, and performcorrective action on those wells:(1) Predict, using computational modeling, theprojected lateral and vertical migration of the carbon dioxideplume and formation fluids in the subsurface from thecommencement of injection activities untilinjection inducedplume movement ceases, pressure differentials sufficient tocause the movement of injected fluids or formation fluids intoa USDW are no longer present, orafterfora fixed timeperiod as determined by the Director. Themodelmodelingmust:ClarificationDecember 23, 2008Carbon Sequestration Council (CCS Contact Group)20 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments146.84(c)(i)(i) Be based on detailed geologic data collected tocharacterize the injection zone, confining zone and anyadditional zones; and anticipated operating data, includinginjection pressures, rates and total volumes over theproposed 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 datacollectedavailableto characterize the injection zone, confining zoneand any additional zones; and anticipated operating data,including injection pressures, rates and total volumes overtheproposed life of the geological sequestration projecttheduration of injection;(ii) Take into accountanyrelevantgeologicheterogeneities,anddata quality, and their possible impacton model predictions; andAllows the use of all available data, not just data collectedspecifically for this permit.(iii) Consider potential migration through faults,fractures, and artificial penetrations.Support the proposed language.Agree with EPA’s rationale.(2) Using methods approved by the Director,identify all penetrations, including active and abandonedwells and underground mines, in the area of review thatmay penetrate the confining zone. Provide a description ofeach well’s type, construction,date drilled, location, depth,record of plugging and/or completion, and any additionalinformation the Director may require; and(2)Using methods approved by the Director,Identifyallknown artificialpenetrationsinto the confining zoneavailable in the public record, including active andabandoned wells and underground mines, in the area ofreview that maypenetratereachthe confining zone. Providea description of each well’stype, construction, date drilled,location, depth, record of plugging and/or completion, andany additional information the Director may require; andChanged for consistency with earlier language.(3) Determine which abandoned wells in the area ofreview have been plugged (as required by § 146.92) in amanner that prevents the movement of carbon dioxide orassociated fluids that may endanger USDWs.(3) Determine which abandoned wellsidentifiedpursuant to 146.84 (c) (2)in the area of reviewhave beenplugged (as required by §146.92) in a manner that preventsthe movement of carbon dioxide orassociatedformationfluids that may endanger USDWs.Remove “in the area of review” as redundant.146.84(d)(d) Owners or operators of Class VI wells mustperform corrective action on all wells in the area of reviewthat are determined to need corrective action usingmethods necessary to prevent the movement of fluid into orbetween USDWs including use of corrosion resistantmaterials, where appropriate.(d) Owners or operatorsof Class VI wells mustperform corrective actionusing materials suitable for use withthe carbon dioxide stream and formation fluids,on all wellsin the area of reviewidentified in 146.84(c)(2)that aredetermined to need corrective action”.using methodsnecessary to prevent the movement of fluid into or betweenUSDWs including use of corrosion resistantmaterials, whereappropriate.Experience with CO2 based EOR strongly supports the use ofmany conventional materials thatmight not meet the technicaldefinition of “corrosion resistant”.December 23, 2008Carbon Sequestration Council (CCS Contact Group)21 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(e) If monitoring data indicate an endangerment toUSDWs, the owner or operator must notify the Director andcease operations as required by § 146.94.(e) If monitoring data indicate an endangerment toUSDWs, the owner or operator must notify the Director andcease operations as required by § 146.94.This is not needed since §146.94 already specifies thenotification and cessation of injection. We suggest deletion ofthis language as unnecessarily duplicative.(f) At the minimum fixed frequency, not to exceed10 years, as specified in the area of review and correctiveaction plan, or when monitoring and operational conditionswarrant, owners or operators must:(1) Reevaluate the area of review in the samemanner specified in paragraph (c)(1) of this section;(2) Identify all wells in the reevaluated area ofreview that require corrective action in the same mannerspecified in paragraph (c)(2) of this section;(f)At the minimum fixed frequency, not to exceed 10years, as specified in the approved area of review andcorrective action plan, orWhen monitoring and operationalconditions warrant, owners or operators must:(1) Reevaluate the area of review in the samemanner specified in paragraph (c)(1) of this section;(2) Identify all wells in the reevaluated area of reviewthat require corrective action in the same manner specified inparagraph (c)(2) of this section;Rather than a fixed time period, we recommend following aperformance based approach that would be based onsignificant changes in injection parameters or anomalousmonitoring results.(3) Perform corrective action on wells requiringcorrective action in the reevaluated area of review in thesame manner specified in paragraph (c)(3) of this section;and(4) Submit an amended area of review andcorrective action plan or demonstrate to the Directorthrough monitoring data and modeling results that noamendment to the area of review and corrective action planis needed.(3) Perform corrective action on wells requiringcorrective action in the reevaluated area of review in thesame manner specified in paragraph (c)(3) of this section;and(4) Submit an amended area of review andcorrective action plan or demonstrate to the Director throughmonitoring data and modeling results that noamendmentchangeto the area of review and corrective action plan isneeded.(4) Clarification146.84(g)(g) The emergency and remedial response plan (asrequired by § 146.94) and a demonstration of financialresponsibility (as described by § 146.85) must account forthe entire area of review, regardless of whether or notcorrective action in the area of review is phased.(g) The emergency and remedial response plan (asrequired by § 146.94) and a demonstration of financialresponsibility (as described by§ 146.85) must account forthe entire area of reviewas modifiedpursuant to § 146.94(f),regardless of whether or not corrective action in the area ofreview is phased.Need to add phrase to account for the periodic reevaluationsand possible revisions that will be occurring.146.85146.85 Financial responsibility(a) The owner or operator must demonstrate andmaintain financial responsibility and resources for correctiveaction (that meets the requirements of § 146.84), injectionwell plugging (that meets the requirements of § 146.92),post-injection site care and site closure (that meets the(a) The owner or operator must demonstrate andmaintain financial responsibility and resources for correctiveaction (that meets the requirements of § 146.84), injectionwell plugging (that meets the requirements of § 146.92),post-injection site care and site closure (that meets theMaintenance of the well plugging financial obligation until siteclosure is not necessary. The Director should have theauthority to release the obligation once the well is plugged.December 23, 2008Carbon Sequestration Council (CCS Contact Group)22 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsrequirements of § 146.93), and emergency and remedialresponse (that meets the requirements of§ 146.94) in a manner prescribed by the Director until:(1) The Director receives and approves thecompleted post-injection site care and site closure plan; and(2) The Director determines that the site hasreached the end of the post-injection site care period.requirements of § 146.93), and emergency and remedialresponse (that meets the requirements of§ 146.94) in a manner prescribed by the Director until:(1) The Director receiveswell plugging reportidentified in 146.92(d) and approvesor completion ofthecompletedpost-injection site care and site closure planasappropriate; and(2) The Director determines that the site has reachedthe end of the post-injection site care period.(b) The owner or operator must provide to theDirector, at a frequency determined by the Director, writtenupdates of adjustments to the cost estimate to account forany amendments to the area of review and corrective actionplan (§ 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 provide to theDirector, at a frequency determined by the Director,but nomore frequently than annually, written updates ofadjustments to the cost estimate to account for anyamendmentschangeto the area of review and correctiveaction plan (§146.84), the injection well plugging plan(§146.92), and the post-injection site care and site closureplan (§146.93).Requiring updates more frequently than annually is notjustified and less frequent updates should be appropriate inmany cases.146.85(c)(c) The owner or operator must notify the Directorof adverse financial conditionssuch as bankruptcy, thatmay affect the ability to carry out injection well plugging andpost-injection site care and site closure.(c) The owner or operator must notify the Director ofadverse financial conditionssuch as bankruptcy,that mayaffect the ability to carry out injection well plugging and postinjection site care and site closure.Clarification.(d) The operator must provide an adjustment of thecost estimate to the Directorif the Director has reason tobelieve that the original demonstration is no longeradequate to cover the cost of injection well plugging (asrequired by § 146.92) and post-injection site care and siteclosure (as required by § 146.93).(d) The operator must provide an adjustment of thecost estimate to the Director if the Director has reason tobelieve thatoriginalthe most recentdemonstration is nolonger adequate to cover the cost of injection well plugging(as required by §146.92) and post-injection site care and siteclosure (as required by §146.93)Clarification.146.866. Injection well construction requirements(a) General. The owner or operator must ensurethat all Class VI wells areconstructed and completed to:(1) Prevent the movement of fluids into or betweenUSDWs or into any unauthorized zones;(2) Permit the use of appropriate testing devicesand workover tools; and6. Injection well construction requirements(a) General. The owner oroperator must ensure thatall Class VI wells are constructed and completed to:(1) Prevent the movement of fluidinto or betweenUSDWs or into any unauthorized zones;containing anycontaminant into USDWs, if thepresence of that contaminantmay cause a violation of any primary drinking waterregulation under 40 CFR part 142 or may otherwiseThe proposed changes follow the non-endangermentstandard that is the basis of the UIC program.December 23, 2008Carbon Sequestration Council (CCS Contact Group)23 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(3) Permit continuous monitoring of the annulusspace between the injection tubing and long string casing.adversely affect the health of persons;(2) Permit the use of appropriate testing devices andworkover tools; and(3) Permit continuous monitoring of the annulusspace between the injection tubing and long string casing.(b) Casing and Cementing of Class VI Wells.(1) Casing and cement or other materials used inthe construction of each Class VI well must have sufficientstructural strength and be designed for the life of thegeologic sequestration project. All well materials must becompatible with fluids with which the materials may beexpected to come into contact and meet or exceedstandards developed for such materials by the AmericanPetroleum Institute, ASTM International, or comparablestandards acceptable to the Director. The casing andcementing program must be designed to prevent themovement of fluids into or between USDWs. In order toallow the Director to determine and specify casing andcementing requirements, the owner or operator mustprovide the following information:(b) Casing and Cementing of Class VI Wells.(1) Casing and cement or other materials used inthe construction of each Class VI well must have sufficientstructural strength and bedesigned for the operatinglife ofthegeologic sequestration projectwell. All well materialsmust becompatiblesuitable for usewith the fluids with whichthe materials may be expected to come into contact andmeet or exceedteststandardsor practicesdeveloped forsuch materials by the American Petroleum Institute, ASTMInternational, or comparable standards acceptable to theDirector. The casing and cementing program must bedesigned to prevent the movement of fluids into or betweenUSDWs. In order to allow the Director to determine andspecify casing and cementing requirements, the owner oroperator must provide the following information:The life of a geologic sequestration project could be differentthan the life of the well. Class VI well design should be basedon the life of the well.146.86(b)(1)(i) Depth to the injection zone;(ii) Injection pressure, external pressure, internalpressure and axial loading;(iii) Hole size;(iv) Size and grade of all casing strings (wallthickness, external diameter, nominal weight, length, jointspecification 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 pressure, internalpressure and axial loading;(iii) Hole size;(iv) Size and grade of all casing strings (wallthickness, external diameter, nominal weight, length, jointspecification and construction material);(v)CorrosivenessCompositionof the carbon dioxidestream and formation fluids; (vi) Down-hole temperaturesand pressures;(vii) Lithology of injection and confining zones;(iv)There is no method for measurement of “corrosiveness” ofa CO2 stream. The relevant information is the composition ofthe CO2 stream.(vi) Technical clarificationDecember 23, 2008Carbon Sequestration Council (CCS Contact Group)24 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(viii) Type or grade of cement; and(ix) Quantity, chemical composition, andtemperature of the carbon dioxide stream.(viii) Type or grade of cementand additives; and(ix) Quantity, chemical composition, and temperatureof the carbon dioxide stream.Technical revision(2) Surface casing must extend through the base ofthe lowermost USDW and be cemented to the surface.(2) Surface casing must extend through the base ofthe lowermost USDWabove the injection zoneand becemented to the surfaceexcept that the Director mayapprove a combination of cemented surface casing andcemented long string casing to achieve continuous cementfrom the surface through thebase of the lowermost USDWabove the injection zone.• Surface casing need not be cemented through thebase of the lowermost USDW if a combination of cement onthe surface casing and long-string casing achievescontinuous cement through the base of the lowermost USDWabove the injection zone. In some parts of the US, USDWsare very deep and this standard may preclude geologicsequestration at otherwise appropriate sites in these areas.(3) At least one long string casing, using a sufficientnumber of centralizers, mustextend to the injection zoneand must be cemented by circulating cement to the surfacein one or more stages.(3) At least one long string casing,using a sufficientnumber of centralizersset in a manner so asto create acement bond through the injection and confining zone(s).Thelong string casingmust extend to the injection zone and mustbecementedisolatedbycirculating cement to the surface inone or more stages.placing cement and/or other isolationtechnologies as necessary to provide adequate isolation ofthe injection zone and provide for protection of USDWs.Cementing of the long string casing to surface is notnecessary to protect USDWs, and may have negativeconsequences. Cement to surface would eliminate the abilityto monitor pressures in this annulus and would limit flexibilityof remedial options. As revised, the proposal would allow forapplication and development of alternative technologies. SeeAPI RP90 for description ofrisk-based approach formanaging situations involving annular casing pressure.Industry experience with CO2 EOR under the Class IIprogram demonstrates the effectiveness of existingcementing procedures.146.86(b)(4) Circulation ofcement may be accomplished bystaging. The Director may approve an alternative methodof cementing in cases where the cement cannot berecirculated to the surface, provided the owner or operatorcan demonstrate by using logs that the cement does notallow fluid movement behind the well bore.(4) Circulation of cement may be accomplished bystaging. The Director may approve an alternative method ofcementing in cases where the cement cannot be recirculatedto the surface, provided the owner or operator candemonstrate by using logs that the cement does not allowfluid movement behind the well bore.Same as above(5) Cement and cement additives must becompatible with the carbon dioxide stream and formationfluids and of sufficient quality and quantity to maintainintegrity over the design life of the geologic sequestrationproject. The integrity and location of the cement shall beverified using technology capable of evaluating cement(5) Cement and cement additives must becompatiblesuitable for usewith the carbon dioxide streamand formation fluids and of sufficient quality and quantity tomaintain integrity over thedesignoperatinglife of thegeologic sequestration projectwell.The integrity and locationof the cement shall be verified using technology capable ofExperience with CO2 EOR under the Class II programdemonstrates the effectiveness of existing cementingmaterials and procedures. Standard API cements have beenused in numerous CO2 EOR operations with no adverseconsequences. Refer to thecitations within EPA’s proposedrule 73 FR 43532-43533: Carey et al., (2007), Crow et al.,December 23, 2008Carbon Sequestration Council (CCS Contact Group)rfvanvoorhees@bryancave.com25Rule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsquality radially and identifying the location of channels toensure that USDWs are not endangered.evaluating cement quality radially and identifying the locationof channels to ensure that USDWs are not endangered.(2008), and Meyer, J.P (2007).146.86(c)(c) Tubing and packer.(1) All owner and operators of Class VI wells mustinject fluids through tubing with a packer set at a depthopposite a cemented interval at the location approved bythe Director.(2) In order for the Director to determine andspecify requirements for tubing and packer, the owner oroperator must submit the following information:(i) Depth of setting;(ii) Characteristics ofthe carbon dioxide stream(chemical content, corrosiveness, temperature, anddensity);(c) Tubing and packer.(1) All owner and operators of Class VI wells mustinject fluids through tubing with a packer set at a depthopposite a cemented interval atthe location approved by theDirector.(2) In order for the Director to determine and specifyrequirements for tubing and packer, the owner or operatormust submit the following information:(i) Depth of setting;(ii)Compositionof the carbon dioxide stream.(chemical content, corrosiveness, temperature, and density);There is no method for measurement of “corrosiveness” of aCO2 stream. The relevant information is the composition, notcharacteristics, of the CO2 stream. The composition of theCO2 stream is more relevant to the design of a tubing andpacker system.146.86(c)(2)(iii) Injection pressure;(iv) Annular pressure;(v) Injection rate (intermittent or continuous) andvolume of the carbon dioxide stream;(vi) Size of casing; and(vii) Tubing tensile, burst, and collapse strengths.(iii)MaximumproposedInjection temperature andpressure;(iv(v)MaximumproposedAnnular pressure;)MaximumproposedInjection rate (intermittent orcontinuous) and volume of the carbon dioxide stream;Technical corrections.146.877. Logging, sampling, and testing prior to injection welloperation(a) During the drilling and construction of a Class VIinjection well, the owner or operator must run appropriatelogs, surveys and tests to determine or verify the depth,thickness, porosity, permeability, and lithology of, and thesalinity of any formation fluids in, all relevant geologicformations to assure conformance with the injection wellconstruction requirements under§ 146.86, and to establishaccurate baseline data against which future measurements(a) During the drilling andconstruction of a Class VIinjection well, the owner or operator must run appropriatelogs, surveys and tests to determine or verify the depth,thickness, porosity, permeability, and lithology of, and thesalinity of any formation fluids in, all relevant geologicformations toassureevaluateconformance with the injectionwell construction requirements under §146.86, and toestablish accurate baseline data against which futuremeasurements may be compared. The owner or operatormust submit to the Director adescriptive report prepared bya knowledgeable log analyst that includes an interpretation ofObtaining the geologic information will not assureconformance with well construction requirements, justmeasure or evaluate it.In well defined areas, these evaluations are frequentlyunnecessary. The Director should have discretion to selectthe appropriate requirements necessary to obtain sufficientbaseline data and information. For example, in an areawhere a number of wells are being drilled, the logging ofsurface hole yields little useful additional information.In particular, this change would allow the Director to reduceDecember 23, 2008Carbon Sequestration Council (CCS Contact Group)26 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsmay be compared. The owner or operator must submit tothe Director a descriptive report prepared by aknowledgeable log analyst that includes an interpretation ofthe results of such logs and tests. At a minimum, such logsand tests must include:the results of such logs and tests.At a minimum, such logsand tests must include:The Director may require such logsand tests as may be needed after taking into account theavailability of similar data inthe area of the drilling site, theconstruction plan, and the need for additional information thatmay arise from time to time asthe construction of the wellprogresses and these may include the following:the requirements when multiple wells are installed for aproject.(1) Deviation checks during drilling on all holesconstructed by drilling a pilot hole which are enlarged byreaming or another method. Such checks must be atsufficiently frequent intervals to determine the location ofthe borehole and to assure that vertical avenues for fluidmovement in the form of diverging holes are not createdduring drilling; andSupport the proposed language.Agree with EPA’s rationale.(2) Before and upon installation of the surfacecasing:Support the proposed language.Agree with EPA’s rationale.(i)Resistivity,spontaneous potential, and caliperlogs before the casing is installed; and(i) Resistivity, spontaneous potential, and caliperlogs before the casing is installed; andAfter a few wells are drilled inan area, these evaluations arefrequently unnecessary and yieldlittle new information. Thisis an example of where modification of requirements basedon Director discretion may be appropriate.(ii) A cement bond and variable density log, and atemperature log after the casing is set and cemented.(ii)ACementbond and variable density log, and atemperature logevaluation log(s) after the casing is set andcemented.Unusual to run these logs in a surface hole due to uniformityof shallow geology. This isan example of where Directordiscretion may be appropriate.The proposed change provides more flexibility to select theappropriate log to demonstrate adequate cement bond.146.87(a)(3) Before and upon installation of the long stringcasing:.Support the proposed language.Agree with EPA’s rationale.December 23, 2008Carbon Sequestration Council (CCS Contact Group)27 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(i)Resistivity,spontaneous potential, porosity,caliper, gamma ray, fracture finder logs, and any other logsthe Director requires for the given geology before thecasing is installed; and(i) Resistivity, spontaneous potential, porosity,caliper, gamma ray,fracture finder logsand any other logsthe Director requiresbased on site specific conditions andrisk-based factorsfor the given geology before the casing isinstalled; andIt is acceptable to specify basic logging requirements,however, special logs should notbe specified. Any otherinformation from the area should be used instead.(ii) A cement bond and variable density log, and atemperature log after the casing is set and cemented(ii)ACementbond and variable density log, and atemperature logevaluation log(s)after the casing is set andcemented.The proposed change provides more flexibility to select theappropriate log to demonstrate adequate cement bond.146.87(a)(4)(4) A series of tests designed to demonstrate theinternal 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-activationlogging;(iii) A temperature or noise log;(iv) A casing inspection log, if required by theDirector; and(4)A series of testsTest(s)designed todemonstrate the internal and external mechanical integrity ofinjection wells, which may include:(i) A pressure test with liquid or gas;(ii)A tracer surveyDiagnostic toolssuch as oxygenactivation logging;(iii) A temperature or noise log;and/or(iv) A casing inspection log.if required by theDirector; andTechnical and grammatical corrections in (4), (4)(ii) and(4)(iii).In (iv), “if required by the Director” is unnecessary.(5) Any alternative methods that provide equivalentor better information and that are required of and/orapproved of by the Director.(5) Any alternative methods that provide equivalentor better informationand that are required of and/orapproved of by theDirector.We interpret that (5) applies to 146.87(a) and support asproposed.For deletion, same comment as above in (iv).146.87(b)(b) The owner or operator must take and submit tothe Director whole cores or sidewall cores of the injectionzone and confining system and formation fluid samplesfrom the injection zone(s). The Director may accept coresfrom nearby wells if the owner or operator can demonstratethat core retrieval is not possible and that such cores arerepresentative of conditions at the well. The Director mayrequire the owner or operator to core other formations in theborehole.(b) The owner or operator must submit to theDirectora report describingwhole cores or sidewall coresrepresentativeof the injection zone and confining system andformation fluid samples from the injection zone(s). TheDirector may acceptdatafromcoresand fluid samplesfromnearby wells if the owner oroperator can demonstrate thatcore retrieval is not possible and thatsuchcoresdataarerepresentative of conditionsatthe wellin the wellbore.TheDirector may require the owner or operator to core otherThe information required should be sufficient to properlydescribe the injection and confining zones.December 23, 2008Carbon Sequestration Council (CCS Contact Group)28 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsformations in the borehole.(c) The owner or operator must record the fluidtemperature, pH, conductivity, reservoir pressure and thestatic fluid level of the injection zone(s).(c)Prior to injection well operation,the owner oroperator mustrecordprovide representative information onthefluidformationtemperature,formation fluidpH andconductivity, and reservoir pressureand the static fluid levelof the injection zone(s).Technical corrections. Reservoir pressure and static fluidlevel are redundant parameters.The phrase “representative information” prevents the operatorfrom having to do all tests in all wells.(d) At a minimum, the owner or operator mustdetermine or calculate the following information concerningthe injection and confining zone(s):(1) Fracture pressure;(2) Other physical and chemical characteristics ofthe injection and confining zones; and(3) Physical and chemical characteristics of theformation fluids in the injection zone.(d) At a minimum, the owner or operator mustdetermine or calculate the following information concerningthe injection and confining zone(s):(1) Fracture pressure;(2) Other physical and chemical characteristics of theinjection and confining zones; and(3) Physical and chemical characteristics of theformation fluids in the injection zone.With the exception of calculating fracture pressure, therequirements of this section appear redundant to otherrequirements of prior sections. The fracture pressurerequirement has been added to section 146.87(e) below.(2) and (3) are too vague.(e) Upon completion, but prior to operation, theowner or operator must conduct the following tests to verifyhydrogeologic characteristics of the injection zone:(1) A pump test; or(2) Injectivity tests.(e)(d)Upon completion butPriortoinjection welloperation, the owner or operator mustconduct the following tests to verifyhydrogeologiccharacteristics of the injection zone:(1) A pump test; or(2) Injectivity tests.estimate fracture pressures of the injection and confiningzonesandinjectivity of the injection zone. Estimates shouldbe based on representative hydrogeologic andgeomechanical characteristics of the injection zone.Allows the use of information such as leak off tests conductedduring the drilling operation.The results of a pump test (pumping fluid from the well) haveno relevance for an injection well.Deletion of the injectivity test would allow the use of nondestructive methods to calculate fracture pressure.146.87(f)(f) The owner or operator must provide the Directorwith the opportunity to witnessall logging and testing by thissubpart. The owner or operator must submit a schedule ofsuch activities to the Director 30 days prior to conductingthe first test and submit any changes to the schedule 30days prior to the next scheduled test.(e) The owner or operator must provide the Directorwith the opportunity to witness all logging and testing by thissubpart. The owner or operator must submit a schedule ofsuch activities to the Directorupon spudding the well andsubmit any changes to the schedule48 hoursprior to thescheduled test.The changes reflect the realities of rig scheduling and arefully consistent with current Class II requirements andpractices.December 23, 2008Carbon Sequestration Council (CCS Contact Group)29 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments146.888. Injection well operating requirements(a) Except during stimulation, the owner or operatormust ensure that injection pressure does not exceed 90percent of the fracture pressureof the injection zone so asto assure that the injection does not initiate new fractures orpropagate existing fractures in the injection zone. In nocase may injection pressureinitiate fractures in theconfining zone(s) or cause the movement of injection orformation fluids that endangers a USDW.(a)The owner or operator must comply with amaximum injection pressure limit approved by the Directorand specified in the permit. In approving a maximum injectionpressure limit, the Director shall consider the results of welltests and, where appropriate, geomechanical or other studiesthat assess the risks of tensile failure and shear failure. TheDirector shall approve limits that, with a reasonable degree ofcertainty, will avoid initiation orpropagation of fractures in theconfining zone or cause otherwise non-transmissive faultstransecting the confining zone to become transmissive. In nocase may injection pressure cause movement of injection orformation fluids in a manner prohibited by 40 CFR Part144.12(a).We are concerned about three aspects of proposed section146.88(a), governing injection pressure limitations. First, it“restricts” fractures in the injection zone “except duringstimulation” rather than focusing on maintaining the integrityof the confining zone, which is what really matters forprotecting USDWs. Second, it fails to refer specifically to thefull range of potential geomechanical failure modes potentiallyposed by operations at a particular site. Third, the type ofgeomechanical risk that is addressed (initiation orpropagation of fractures), is dealt with in a potentiallyarbitrary fashion (the 90% of fracture pressure limit), whichmay not be appropriate in all cases.Our recommended language addresses these concerns byfocusing on maintaining the integrity of the confining zone andincluding tensile failure and shear failure as transmissivityconcerns. It calls for additional geomechanical studies oftensile failure and shear failure only “where appropriate”because there will be locationswhere experienceor existinginformation will provide sufficient evidence to avoid the needfor additional studies. The need for conducting additionaltests and for determining which tests would be acceptable isleft to the Director’s discretion.This is the same recommendation as presented by the multistakeholder group, in which the Carbon SequestrationCouncil participated.(b) Injection between the outer-most casingprotecting USDWs and the well bore is prohibited.(b) Injectionof the CO2 streambetween theoutermost casing protecting USDWs and the well bore isprohibited.Routine injection into zones other than the target interval(s)should be prohibited, however, wording of this requirement isnot clear as to which interval isbeing addressed. An absoluteprohibition on injection into this annulus may also limitdiagnostic or remedial options that could be useful.(c) The owner or operator must fill the annulusbetween the tubing and the long string casing with a noncorrosive fluid approved by the Director. The owner oroperator must maintain on the annulus a pressure thatexceeds the operating injection pressure, unless theDirector determines that suchrequirement might harm theintegrity of the well.(c) The owner or operator must fill the annulusbetween the tubing and the long string casing with a noncorrosive fluid approved by the Director. The owner oroperator must maintain a positive pressure on the annulus.Industry experience with the Class II UIC program does notsupport this requirementas proposed by EPA.Positive annular pressure that exceeds the operating injectionpressure is not necessary because a leak from tubing toannulus does not have the same implications as in a Class Ihazardous situation.December 23, 2008Carbon Sequestration Council (CCS Contact Group)30 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments146.88(d)(d) Other than during periods of well workover(maintenance) approved by the Director in which the sealedtubing-casing annulus is of necessity disassembled formaintenance or corrective procedures, the owner oroperator must maintain mechanical integrity of the injectionwell at all times.Support the proposed language..Agree with EPA’s rationale(e) The owner or operator must install and usecontinuous recording devices to monitor: The injectionpressure; the rate, volume, andtemperature of the carbondioxide stream; and the pressure on the annulus betweenthe tubing and the long string casing and annulus fluidvolume; and must install and use alarms and automaticdown-hole shut-off systems, designed to alert the operatorand shut-in the well when operating parameters such asannulus pressure, injection rate or other parametersapproved by the Director diverge beyond permitted rangesand/or gradients specified in the permit;(e) The owner or operator must install and usecontinuous recording devices to monitor: the injectionpressure; the rate, volume, and temperature of the carbondioxide streamand.The owner or operator must regularlymonitorthe pressure on the annulus between the tubing andthe long string casingand annulus fluid volumeand.Theowner or operatormust install and use alarms and automaticdown-holeshut-off systems, designed to alert the operatorand shut-in the well when operating parameters such asinjection rate, injection pressure, or other parametersapproved by the Director diverge beyond ranges and/orgradients specified in the permit;Over-pressure protection is best achieved by ensuringcompatibility of the casing/tubing material design strengthwith the surface injection (compression) system. Down-holeshut-in devices are not appropriate for this application. Thesedevices are installed in the tubing string and are typically nearthe surface of the well. They’reintended to seal the tubing inthe event of catastrophic failure of the wellhead. Thesedevices would provide little ifany protection to USDWs. Isnot practicable to install these devices deep within the well(e.g. shortly above the packer). Additionally these devicescreate a restriction on running other tools like logging tools inthe well and therefore could limit an operators ability to dorequired monitoring and diagnostic work. Lastly, thesedevices require periodic testing and maintenance which couldrequire either pulling the device by wireline or by pulling theentire tubing string depending onthe type of device installed.Either of these activities would be disruptive and costly to theoverall project operations.(f) If a down-hole automatic shutdown is triggeredor a loss of mechanical integrity is discovered, the owner oroperator must immediately investigate and identify asexpeditiously as possible the cause of the shutoff. If, uponsuch investigation, the well appears to be lackingmechanical integrity, or if monitoring required underparagraph (e) of this section otherwise indicates that thewell may be lacking mechanical integrity, the owner oroperator must:(f) If andown-holeautomatic shutdown is triggeredor a loss of mechanical integrity is discovered, the owner oroperator must immediately investigate and identify asexpeditiously as possible the causeof the shutoff. If, uponsuch investigation, the well appears to be lacking mechanicalintegrity, or if monitoring required under paragraph (e) of thissection otherwise indicates that the well may be lackingmechanical integrity, the owner or operator must:Revisions made here to make this subsection conform withchanges to 146.88(e) above.December 23, 2008Carbon Sequestration Council (CCS Contact Group)31 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments146.88(f)(1) Immediately cease injection;(2) Take all steps reasonably necessary todetermine whether there may have been a release of theinjected carbon dioxide streaminto any unauthorized zone;(3) Notify the Director within 24 hours;(4) Restore and demonstrate mechanical integrityto the satisfaction of the Director prior to resuming injection;and(5) Notify the Director when injection can beexpected to resume.(1) Immediately cease injection;(2) Take all steps reasonably necessary todetermine whether there mayhave been a release of theinjected carbon dioxide stream into any unauthorized zone;(3) Notify the Director within 24 hoursof discovery;(4) Restore and demonstrate mechanical integrity tothe satisfaction of the Directorprior to resuming injection;and(5) Notify the Director when injection can beexpected to resume.Clarifying revision to (3) will make compliance feasible foroperators.146.899. Mechanical integrity(a) A Class VI well has mechanical integrity if:(1) There is no significantleak in the casing, tubingor packer; and(2) There is no significant fluid movement into aUSDW through channels adjacent to the injection well bore.Support the proposed language.Agree with EPA’s rationale.(b) To evaluate the absence of significant leaksunder paragraph (a)(1) of this section, owners or operatorsmust, following an initial annulus pressure test, continuouslymonitor injection pressure, rate, injected volumes, andpressure on the annulus between tubing and long stemcasing and annulus fluid volume as specified in § 146.88(e);(b) To evaluate the absence of significant leaksunder paragraph (a)(1) of this section, owners or operatorsmust, following an initial annulus pressure test, continuouslymonitorand record at least daily, annulus pressure andvolumes of fluid added to or removed frominjectionpressure, rate, injected volumes, and pressure ontheannulus betweenthetubing and longstemstringcasingandannulus fluid volumeas specified in §146.88 (e);We recommend continuous monitoring, but do not findcontinuous recording necessary as Class II requirementshave proven sufficient. The alternative of continuousmonitoring, which will alert operator to any problems, anddaily recording to allow for daily check of wells. This isconsistent with successfulClass II operating experience.December 23, 2008Carbon Sequestration Council (CCS Contact Group)32 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments146.89(c)(c) At least once peryear, the owner or operatormust use one of the following methods to determine theabsence of significant fluid movement under paragraph(a)(2) of this section:(1) A tracer survey such as oxygen-activationlogging;(2) A temperature or noise log; or(3) A casing inspection log, if required by theDirector.(c) At least once per year, the owner or operatormust confirm the absence ofsignificant fluid movementunder paragraph (a)(2) of this sectionusing a methodacceptable to the Director(e.g. including diagnostic surveyssuch as oxygen-activation logging or temperature or noiselogs).(1) A tracer survey suchas oxygen-activationlogging;(2) A temperature or noise log; or(3) A casing inspection log, if required by theDirector.Revised text supports a performance-based approach andallows the development and use of new technologies as theybecome available. Cement circulation to the surface is notnecessary because having the open annulus above the top ofcement allows regular monitoring of annular pressure whichcould indicate leakage.We recommend deletion of subsection (3) because it wouldrequire that the tubing be pulled atsignificant cost and risk ofuncontrolled releases.(d) The Director may require any other test toevaluate mechanical integrity under paragraph (a)(1) or(a)(2) of this section. Also, the Director may allow the useof a test to demonstrate mechanical integrity other thanthose listed above with the written approval of theAdministrator. To obtain approval, the Director must submita written request to the Administrator, which must set forththe proposed test and all technical data supporting its use.The Administrator must approvethe request if it will reliablydemonstrate the mechanical integrity of wells for which itsuse is proposed. Any alternate method approved by theAdministrator will be published in the Federal Register andmay be used in all States in accordance with applicableState law unless its use is restricted at the time of approvalby the Administrator.Support the proposed language.Agree with EPA’s rationale.146.89(e)(e) In conducting and evaluating the testsenumerated in this section or others to be allowed by theDirector, the owner or operator and the Director must applymethods and standards generallyaccepted in the industry.When the owner or operator reports the results ofmechanical integrity tests to the Director, he/she shallinclude a description of the test(s) and the method(s) used.In making his/her evaluation, the Director must reviewmonitoring and other test data submitted since the previousevaluation.Support the proposed language.Agree with EPA’s rationale.December 23, 2008Carbon Sequestration Council (CCS Contact Group)33 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(f) The Director may require additional or alternativetests if the results presented bythe owner or operator underparagraph (d) of this section are not satisfactory to theDirector to demonstrate that there is no significant leak inthe casing, tubing or packer or significant movement of fluidinto or between USDWs resulting from the injection activityas stated in paragraphs (a)(1) and (2) of this section.Support the proposed language.Agree with EPA’s rationale.146.9010. Testing and monitoring requirementsThe owner or operator of a Class VI well must prepare,maintain, and comply with a testing and monitoring plan toverify that the geologic sequestration project is operating aspermitted and is not endangering USDWs. The testing andmonitoring plan must be submitted with the permitapplication, for Director approval, and must include adescription of how the owneror operator will meet therequirements of this section. Testing and monitoringassociated with geologic sequestration projects must, at aminimum, include:(a) Based on a site-specific assessment of thepotential for fluid movement from the injection well orinjection zone, and on the potential value of monitoring wellsto detect such movement,the owner or operator of a ClassVI well must prepare, maintain, and comply with a testingand monitoring planto verify that the geologic sequestrationproject is operating as permitted and is not endangeringUSDWs. The testing and monitoring plan must be submittedwith the permit application, for Director approval and includea description of how the owner or operator will meet therequirements of this section;Drilling monitoring wells should be carefully considered sinceeach well introduces a potential pathway for fluid movement.In addition the cost of adding multiple wells could create abarrier to CCS development, while providing limitedinformation on actual movement of the CO2 stream.146.90(a) Analysis of the carbon dioxide stream withsufficient frequency to yield data representative of itschemical and physical characteristics;(b) Installation and use, except during wellworkovers as defined in § 146.86(d), of continuousrecording devices to monitor injection pressure, rate andvolume; the pressure on the annulus between the tubingand the long string casing; and the annulus fluid volume;(b) The testing and monitoring plan must, at aminimum, include:(1)analysis of the carbondioxide stream withsufficient frequency to yield data representative of itschemical and physical characteristics;(2)Installation and use, except during wellworkovers as defined in section 146.88(d), of continuousmonitoring devices(including digital devices capturingperiodic data)to monitor injection pressure, rate and volume;and record at least dailythe pressure on the annulusbetween the tubing and the long strong casing;(3) a demonstration of external mechanical integritypursuant to §146.89(c) until the well is plugged;(4) monitoring of the pressure buildup in theinjection zone annually, including at a minimum, a shut downThere is concern regarding what constitutes continuousmonitoring. Industry agrees thatregular monitoring of theparameters identified by EPA is appropriate. Experience withCO2 EOR strongly shows that daily monitoring of most ofthese parameters is adequate (exceptions to this would be ona site-specific basis). Recording should generally be done ona daily basis and reporting on a semi-annual basis.December 23, 2008Carbon Sequestration Council (CCS Contact Group)34 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsof the well for a time sufficient to conduct a valid observationof the pressure fall-off curve at least once every five years;and(5) a quality assurance plan for all testing andmonitoring requirements.146.90(c) Corrosion monitoring of the well materials forloss of mass, thickness, cracking, pitting and other signs ofcorrosion must be performed on a quarterly basis to ensurethat the well components meet the minimum standards formaterial strength and performance set forth in § 146.86(b)by:(1) Placing coupons of the well constructionmaterials in contact with the carbon dioxide stream; or(2) Routing the carbon dioxide stream through aloop constructed with the material used in the well; or(3) Using an alternative method approved by theDirector;(c) Where appropriate, the testing and monitoringplan shall also include:(1) Continuous monitoring for pressure changes inan appropriately porous and permeable formation overlyingthe confining zone.;(2) The use of indirect, geophysical techniques todetermine the position of the CO2 stream front, the waterquality in a designated formation, or to provide other sitespecific data;(3) Periodic monitoring of water quality in anappropriately porous and permeable formation overlying theinjection zone;(4) Periodic monitoring of water quality in one ormore USDWs;(5) Corrosion monitoring of the well materials forloss of mass, thickness, cracking, pitting and other signs ofcorrosion performed and recorded at least quarterly whichmay be modified to be less frequent as approved by theDirector based on construction materials, operatingconditions, and monitoring history to ensure that the wellcomponents meet the minimum standards for materialstrength and performance set forth in §146.86(b) by:There should be no need for corrosion monitoring of mostinjected CO2 streams because those streams will typicallyoverwhelmingly CO2 and drythus having no corrosiveproperties. Industry experience with production,transportation, and injection of dry CO2 strongly illustrates thenon-corrosive nature of this type of CO2 stream.This proposal revises the provision to make it a requirementonly where appropriate based on the materials of constructionand characteristics of the injected CO2 stream and otherfactors.The corrosion provisions are included in subsection (c)(5).December 23, 2008Carbon Sequestration Council (CCS Contact Group)35 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(i) Analyzing coupons of the well constructionmaterials placed in contact with the carbon dioxide stream; or(ii) Routing the carbon dioxide stream through aloop constructed with the material used in the well andinspecting the materials in the loop; or(iii) Using an alternative method, materials, or timeperiod approved by the Director;(6) Any additional testing and monitoring necessaryto support modeling the extent of the carbon dioxide plumeand the position of the pressure front; and(7) Any additional testing and monitoring necessaryto determine whether fluid movement is occurring into orbetween USDWs that would endanger a USDW.146.90(d)(d) Periodic monitoring of the ground water qualityand geochemical changes above the confining zone(s) thatmay be a result of carbon dioxide movement through theconfining zone or additional identified zones:(1) The location and number of monitoring wellsmust be based on specific information about the geologicsequestration project, including injection rate and volume,geology, the presence of artificial penetrations and otherfactors;(2) The monitoring frequency and spatialdistribution of monitoring wells must be based on baselinegeochemical data that has been collected under §146.82(a)(6) and any modeling results in the area of reviewevaluation required by § 146.84(b);(d) Periodic monitoring of the ground water qualityand geochemical changes above the confining zone(s) thatmay be a result of carbon dioxide movement through theconfining zone or additional identified zones:(1) The location and number of monitoring wellsmust be based on specific information about the geologicsequestration project, including injection rateand volume,geology, the presence of artificial penetrations and otherfactors;(2) The monitoring frequency and spatial distributionof monitoring wells must be based on baseline geochemicaldata that has been collectedunder § 146.82(a)(6) and anymodeling results in the area of review evaluation required by§ 146.84(b);146.90(e) A demonstration of external mechanical integritypursuant to § 146.89(c) at least once per year throughoutthe duration of the geologic sequestration project;(f) A pressure fall-off test at least once every fiveyears unless more frequent testing is required by theDirector based on site specific information;(e) A demonstration of external mechanical integritypursuant to § 146.89(c) at least once per year throughout theduration of the geologic sequestration project;(f) A pressure fall-off test at least once every fiveyears unless more frequent testing is required by the Directorbased on site specific information;Redundant to section 146.89These issues are addressed in recommended subsection(b)(3) and (4).December 23, 2008Carbon Sequestration Council (CCS Contact Group)36 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(g) Testing and monitoringto track the extent of thecarbon dioxide plume and the position of the pressure frontby either monitoring for pressure changes in the firstformation overlying the confining zone or using indirect,geophysical techniques (e.g., seismic, electrical, gravity, orelectromagnetic surveys and/or down-hole carbon dioxidedetection tools);(g) Testing and monitoring to track the extent of thecarbon dioxide plume and the position of the pressure frontby either monitoring for pressure changes in the firstformation overlying the confining zone or using indirect,geophysical techniques (e.g., seismic, electrical, gravity, orelectromagnetic surveys and/or down-hole carbon dioxidedetection tools);Monitoring outside of the injection zone provides littleinformation of value for tracking and monitoring the injectedplume. Examples of how to test and monitor could beincluded in the Preamble but need not be included in the ruleitself.146.90(h) At the Director’sdiscretion, surface aimonitoring and/or soil gas monitoring to detect movementof carbon dioxide that could endanger a USDW.r(1) The testing and monitoring plan must be basedon potential vulnerabilities within the area of review;(2) The monitoring frequency and spatialdistribution of surface airmonitoring and/or soil gasmonitoring must reflect baseline data and the monitoringplan must include how the proposed monitoring will yielduseful information on the area of review delineation and/orcompliance with standards under 40 CFR 144.12;(h) At the Director’s discretion, surface air monitoringand/or soil gas monitoring to detect movement of carbondioxide that could endanger a USDW.(1) The testing and monitoring plan must be basedon potential vulnerabilities within the area of review;(2) The monitoring frequency and spatial distributionof surface air monitoring and/or soil gas monitoring mustreflect baseline data and the monitoring plan must includehow the proposed monitoring will yield useful information onthe area of review delineation and/or compliance withstandards under 40 CFR 144.12;In most situations soil and air monitoring does not provide aneffective method of protecting USDWs.146.90(i)(i) Any additional monitoring, as required by theDirector, necessary to support, upgrade, and improvecomputational modeling of the area of review evaluationrequired under § 146.84(b) and to determine compliancewith standards under 40 CFR 144.12; and(j) A quality assurance and surveillance plan for alltesting and monitoring requirements.(i) Any additional monitoring, as required by theDirector, necessary to support, upgrade, and improvecomputational modeling of the area of review evaluationrequired under §146.84(b) and to determine compliance withstandards under 40 CFR 144.12; and(j) A quality assurance andsurveillance plan for alltesting and monitoring requirements.These issues are addressed insubsection (c)(6) and (b)(5)respectively.146.9111. Reporting requirements.The owner or operator must, at a minimum, provide thefollowing reports to the Director, for each permitted Class VIwell:(a) Semi-annual reports containing:The owner or operator must, at a minimum, provide thefollowing reports to the Director, for each permitted Class VIwell:(a) Semi-annualor less frequent at the discretion ofthe Directorreports containing:(1) Anysignificantchanges to the physical, chemicalOver the life of the project, the Director may decide that lessreporting is acceptable(1) Technical clarification. Significance can be determined bya statistical analysis of the data.Rules should recognize thatDecember 23, 2008Carbon Sequestration Council (CCS Contact Group)37 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(1) Any changes to the physical, chemical andother relevant characteristicsof the carbon dioxide streamfrom the proposed operating data;(2) Monthly average, maximum and minimumvalues for injection pressure, flow rate and volume, andannular pressure;and other relevant characteristics of the carbon dioxidestream from the proposed operating data;(2) Monthly average, maximum and minimum valuesfor injection pressure, flow rate and volume, and annularpressure;there will be minor variations inmany data sets over time.146.91(a)(3) A descriptionof any event that exceedsoperating parameters for annulus pressure or injectionpressure as specified in the permit;(4) A description of any event which triggers ashutdown device required pursuant to § 146.88(e) and theresponse taken;(5) The monthly volume of the carbon dioxidestream injected over the reporting period and projectcumulatively;(6) Monthly annulus fluid volume added; and(7) The results of monitoring prescribed under §146.90.(3) A description of anysignificantevent thatexceeds operating parameters for annulus pressure orinjection pressure as specified in the permit;(4) A description of anysignificantevent whichtriggers a shutdown device required pursuant to §146.88(e)and the response taken;(5) The monthly volume of the carbon dioxidestream injected over the reporting period and projectcumulatively;(6) Monthly annulus fluid volume added; and(7) The results of monitoring prescribed under §146.90.EPA should consider some significance threshold onreporting these events to avoidreporting events that would beof limited interest or consequence.(b) Report, within 30 days the results of:(1) Periodic tests of mechanical integrity;(2) Any other test of the injection well conducted bythe permittee if required by the Director; and(3) Any well workover.(c) Owners or operators must submit reports in anelectronic format acceptableto the Director. At thediscretion of the Director, other formats may be accepted.Support the proposed language.Agree with EPA’s rationale.146.9212. Injection well plugging.(a) Prior to the well plugging, the owner or operatormust flush each Class VI injection well with a buffer fluid,determine bottomhole reservoir pressure, and perform afinal mechanical integrity test.(a) Prior to the well plugging, the owner or operatormust flush each Class VI injection well with a buffer fluid,determine bottomhole reservoir pressure, and perform a finalexternalmechanical integrity testof any relevant wellborematerials remaining.Many of the components that would be tested by an internalMIT are removed or tested during the plugging process.December 23, 2008Carbon Sequestration Council (CCS Contact Group)38 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments146.92(b)(b) Well Plugging Plan. The owner or operator of aClass VI well must prepare, maintain, and comply with aplan that is acceptable to theDirector. The requirement tomaintain and implement an approved plan is directlyenforceable regardless of whether the requirement is acondition of the permit. The well plugging plan must besubmitted as part of the permit application and must includethe following information:Support the proposed language.Agree with EPA’s rationale.(1) Appropriate test or measure to determinebottomhole reservoir pressure;(2) Appropriate testing methods to ensuremechanical integrity as specified in § 146.89;(3) The type and number of plugs to be used;(4) The placement of each plug including theelevation of the top and bottom of each plug;(5) The type and grade and quantity of material tobe used in plugging. The material must be compatible withthe carbon dioxide stream; and(6) The method of placement of the plugs.(1) Appropriate test or measure to determinebottomhole reservoir pressure;(2) Appropriate testing methods to ensurefinalexternalmechanical integrity as specified in §146.89(c);(3) The type and number of plugs to be used;(4) The placement of each plug including theelevation of the top and bottom of each plug;(5) The type and grade and quantity of material tobe used in plugging. The material must besuitable for usewith the carbon dioxide stream; and(6) The method of placement of the plugs.Many of the components that would be tested by an internalMIT are removed or tested during the plugging process.(c) Notice of intent to plug. The owner or operatormust notify the Director at least 60 days before plugging ofa well. At this time, if any changes have been made to theoriginal well plugging plan, the owner or operator must alsoprovide the revised well plugging plan. At the discretion ofthe Director, a shorter notice period may be allowed.Support the proposed language.Agree with EPA’s rationale.146.92(d)(d) Plugging report. Within 60 days after pluggingor at the time of the next semi-annual report (whicheveroccurs earlier) the owner or operator must submit aplugging report to the Director. If the semi-annual report isdue less than 15 days after completion of plugging, then thereport must be submitted within 60 days after plugging. Thereport must be certified as accurate by the owner oroperator and by the personwho performed the pluggingoperation (if other than the owner or operator.)(d) Plugging report. Within 60 days after pluggingthe owner or operatormust submit a plugging report to theDirector.If the semi-annual report is due less than 15 daysafter completion of plugging, then the report must besubmitted within 60 days after plugging.The report must becertified as accurate by theowner or operator and by theperson who performed the plugging operation (if other thanthe owner or operator.)The proposed change will simplify and clarify a provision thatis unnecessarily complicated.146.9313. Post-injection site care and site closure(a) The owner or operator of a Class VI well mustPost-injection site care and site closure(a) The owner or operator of a Class VI well mustRevisions here reflect changes to §146.93(b)(3)December 23, 2008Carbon Sequestration Council (CCS Contact Group)39 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Commentsprepare, maintain, and comply with a plan for post-injectionsite care and site closure that meets the requirements ofparagraph (a)(2) of this section and is acceptable to theDirector.(1) The owner or operator must submit the postinjection site care and site closure plan as a part of thepermit application to be approved by the Director.prepare, maintain, and comply with a plan for post-injectionsite care and site closure that meets the requirements ofparagraph (a)(2) of this section and is acceptable to theDirector.(1) The owner or operatormust submit the postinjection site care and site closure plan as a part of thepermit application to be approved by the Director.shallcontinue to conduct monitoring as specified in the Directorapproved post-injection site care and site closure plan,pursuant to the performance based criteria described in146.93(b)(3).(2) The post-injection site care and site closure planmust include the following information:(i) The pressure differential between pre-injectionand predicted post-injection pressures in the injection zone;(ii) The predicted position of the carbon dioxideplume and associated pressurefront at site closure asdemonstrated in the area of review evaluation requiredunder § 146.84(b);(2) The post-injection site care and site closure planmust include the following information:(i) The pressure differential between pre-injectionand predicted post-injection pressures in the injection zone;(ii) The predicted position of the carbon dioxideplume and associated pressurefront at site closure asdemonstrated in the area of review evaluation required under§ 146.84(b);Revisions here reflect changes to §146.93(b)(3)146.93(a)(2)(iii) A description of post-injection monitoringlocation, methods, and proposed frequency; and(iv) A proposed schedule for submitting postinjection site care monitoring results to the Director.(iii) A description of post-injection monitoringlocation, methods, and proposed frequency; and(iv) A proposed schedule for submitting post-injectionsite care monitoring results to the Director.(3) Upon cessation of injection, owners or operatorsof Class VI wells must either submit an amended postinjection site care and site closure plan or demonstrate tothe Director through monitoring data and modeling resultsthat no amendment to the plan is needed.Support the proposed language.Agree with EPA’s rationale.(4) The owner or operator may modify and resubmit thepost-injection site care and site closure plan for theDirector’s approval within 30 days of such change.4)At any time during the post-injection site carephase, the owner or operator may modify and resubmit thepost-injection site care and site closure plan for the Director’sapproval within 30 days of such change.Technical Clarification.December 23, 2008Carbon Sequestration Council (CCS Contact Group)40 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments146.93(b)(b) The owner or operator shall monitor the sitefollowing the cessation of injection to show the position ofthe carbon dioxide plume and pressure front anddemonstrate that USDWs are not being endangered.(1) The owner or operator shall continue to conductmonitoring as specified in the Director-approved postinjection site care and site closure plan for at least 50 yearsfollowing the cessation of injection. At the Director’sdiscretion, the monitoring will continue until the geologicsequestration project no longer poses an endangerment toUSDWs.(b) The owner or operator shall monitor the sitefollowing the cessation of injectionto show the position of thecarbon dioxide plume and pressure front and demonstratethat USDWs are not being endangered.(1) The owner or operator shall continue to conductmonitoring as specified in the Director-approved postinjection site care and site closure plan,until closure isauthorized pursuant to 146.93(b)(3).EPA should also reconsider its proposed 50-year defaultperiod for post-injection site care. EPA offers no rationale forthis arbitrarily-selected period of 50 years. Establishing afixed and unusually long time period may create a significantbarrier for operators considering entry into CCS operations.Criteria for determining the period for post-injection site careshould be performance-based and a function of the sitespecific characteristics of a project such as project size,geologic factors, and relative risk of the project. Such criteriaare provided in our edits to §146.93(b)(3).146.93(b)(2) If the owner or operator can demonstrate to thesatisfaction of the Directorbefore 50 years, based onmonitoring and other site-specific data, that the geologicsequestration project no longer poses an endangerment toUSDWs, the Director may approve an amendment to thepost-injection site care and site closure plan to reduce thefrequency of monitoring or may authorize site closurebefore the end of the 50-year period.(2) If the owner or operator can request anddemonstrate to the satisfaction of the Directorbefore 50years, based on monitoring and other site-specific data, thatthe geologic sequestration project no longer poses anendangerment to USDWs, the Director may approve anamendment tothatthe post-injection site care and siteclosure planshould be revisedto reduce the frequency ofmonitoring, the Director shall approve the reduction.or mayauthorize site closure before the end of the 50-year period.See rationale stated above for eliminating 50-year period.(3) Prior to authorization for site closure, the owneror operator must submit tothe Director a demonstration,based on monitoring and other site-specific data, that thecarbon dioxide plume and pressure front have stabilizedand that no additional monitoring is needed to assure thatthe geologic sequestration project does not pose anendangerment to USDWs.(3) Prior to authorization for site closure, the owneror operator mustdemonstrate to the Director, based onmonitoring, other site-specific data, and modeling that isreasonably consistent with site performance, that noadditional monitoring is needed to assure that the geologicsequestration project does not and is not expected to posean endangerment to USDWs.The Director shall approveclosure if the owner or operator demonstrates, based on thecurrent understanding of the site, including monitoring dataand/or modeling, all of the following: (i) the estimatedmagnitude and extent of the project footprint (CO2 plumeand the area of elevated pressure) ; (ii) the estimatedlocation of the detectable CO2 plume; (iii) that there is nosignificant leakage of either CO2 or displaced formationfluids that is endangering USDWs; (iv) that the injected ordisplaced fluids are not expected to migrate in the future in amanner that encounters a potential leakage pathway into aUSDW; (v) that the injection wells at the site completed intoor through the injection zone or confining zone are pluggedand abandoned in accordance with these requirements; andWe believe there are three problems with the closurestandard in proposed section 146.93(b). First, thepresumption that monitoring should continue for 50 years isunnecessary and counterproductive. A straight performancestandard is preferable to this or any other fixed time periodbecause it provides a clearerstandard and an incentive tomaximize the understanding of site and project performanceand as such is more protective of USDWs. Second, theproposal requires a showing that the CO2 plume has“stabilized”, which is undefined. Cessation of plumemovement is not necessarily essential to show that a projectposes no threat of endangerment to USDWs—plumes thatare still moving may, nonetheless, remain contained. Instead,it is more protective to show that the plume is not expected toencounter a leakage pathway. Third, the required showingthat “no additional monitoring is needed” does not provideguidance regarding how an operator is to show that noadditional monitoring is needed. The proposal belowprovides specific guidance on what the operator must show.December 23, 2008Carbon Sequestration Council (CCS Contact Group)41 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(vi) any remaining project monitoring wells at the site arebeing managed by a person and in a manner acceptable tothe Director.We recommend the standard in the proposed alternativelanguage for section 146.93(b) below because it sets forthdetailed criteria, all of which must be satisfied, to demonstratethat the site does not pose anendangerment to USDWs. Thespecific criteria listed in our proposal will serve to provide theDirector with the requisite information to make the appropriatedetermination. The advantage of this approach is that itestablishes clear criteria thatan operator must demonstratebefore obtaining site closure based upon particular sitecharacteristics and is, therefore, reasonably applicable to anystorage site as opposed to a standard based upon a fixedduration. Furthermore, it is more stringent than a purelydiscretionary approach because itestablishes specific criteriathat must be shown before site closure may be granted. Webelieve this language, which is an extension of work done bythe World Resources Institute and the Ground WaterProtection Council, avoids the noted shortcomings andprovides stronger protection for USDWs.This is the same recommendation as presented by the multistakeholder group, in which the Carbon SequestrationCouncil participated.(4) If such a demonstration cannot be made (i.e., ifthe carbon dioxide plume and pressure front have notstabilized) after the 50-year period, the owner or operatormust submit to the Director aplan to continue post-injectionsite care.(4) If such a demonstration cannot bemade (i.e., ifthe carbon dioxide plume and pressure front have notstabilized) after the 50-year period, the owner or operatormust submit to the Director a plan to continue post-injectionsite care.No longer necessary with 50-year period deletion.146.93(c)(c) Notice of intent for site closure. The owner oroperator must notify the Director at least 120 days beforesite closure. At this time, if any changes have been madeto 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 maybe allowed.Support the proposed language.Agree with EPA’s rationale.146.93(d)(d) After the Director has authorized site closure,the owner or operator must plug all monitoring wells in amanner which will not allow movement of injection orformation fluids that endangers a USDW.Support the proposed language.Agree with EPA’s rationale.December 23, 2008Carbon Sequestration Council (CCS Contact Group)42 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(e) Once the Director has authorized site closure,the owner or operator must submit a site closure reportwithin 90 days that must thereafter be retained at a locationdesignated by the Director. The report must include:(1) Documentation of appropriate injection andmonitoring well plugging as specified in § 146.92 andparagraph (c) of this section.The owner or operator mustprovide a copy of a survey plat which has been submitted tothe local zoning authority designated by the Director. Theplat must indicate the location of the injection well relative topermanently surveyed benchmarks. The owner or operatormust also submit a copy of the plat to the RegionalAdministrator of the appropriate EPA Regional Office;(e) Once the Directorhasauthorizesdsite closure,the owner or operator must submita site closure report within90 daysthat must thereafter be retained at a locationdesignated by the Director.after completion of all closureoperations. The report must include:(1) Documentation of appropriate injection andmonitoring well plugging as specified in §146.92 andparagraph (c) of this section.The owner or operator mustprovide a copy of a survey plat which has been submitted tothe local zoning authority designated by the Director. Theplat must indicate the location of the injection well(s)relativeto permanently surveyed benchmarks. The owner or operatormust also submit a copy of the plat to the RegionalAdministrator of the appropriate EPA Regional Office;Once the site closure report is submitted to the Director, theoperator cease to bear responsibility for any further recordretention. At this point, EPA becomes the steward ofinformation for the project.(2) Documentation of appropriate notification andinformation to such State, local and tribal authorities ashave authority over drilling activities to enable such Stateand local authorities to impose appropriate conditions onsubsequent drilling activities that may penetrate theinjection and confining zone(s); and(3) Records reflecting the nature, composition andvolume of the carbon dioxide stream.Support the proposed language.Agree with EPA’s rationale.146.93(f) Each owner or operator of a Class VI injectionwell must record a notation on the deed to the facilityproperty or any other documentthat is normally examinedduring title search that will in perpetuity provide anypotential purchaser of the property the followinginformation:(1) The fact that land has been used to sequestercarbon dioxide;(2) The name of the State agency, local authority,and/or tribe with which the surveyplat was filed, as well asthe address of the RegionalEnvironmental ProtectionAgency Office to which it was submitted; andSupport the proposed language.Agree with EPA’s rationale.December 23, 2008Carbon Sequestration Council (CCS Contact Group)43 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(3) The volume of fluid injected, the injection zoneor zones into which it was injected, and the period overwhich injection occurred.(g) The owner or operator must retain for threeyears following site closure, records collected during thepost-injection site care period. The owner or operator mustdeliver the records to the Director at the conclusion of theretention period, and the records must thereafter beretained at a location designated by the Director for thatpurpose.Support the proposed language.Agree with EPA’s rationale.146.9414. Emergency and remedial response.(a) As part of the permit application, the owner oroperator must provide the Director with an emergency andremedial response plan that describes actions to be takento address movement of the injection or formation fluids thatmay cause an endangerment to a USDW duringconstruction, operation, closure and post-closure periods.(a) As part of the permit application, the owner oroperator must provide the Director with an emergencya riskbasedremedial response plan that describes actions to betaken to address movement of the injection or formationfluids that may cause an endangerment to a USDW duringconstruction, operation, closure and post-closure periods.Any response plan should be based on a risk assessmentand risk management approach that accounts not only forpotential causes of endangerment, but probabilities andpotential timing of occurrence as determined on a site-specificbasis. As EPA has recognized, “The SDWA does not provideauthority to develop regulations for all areas related to GS.”73 Fed. Reg. at 43495. Accordingly, the nature and scope ofany such plans will necessarily be limited tothe extent of thatauthority..146.94(b)(b) If the owner or operator obtains evidence thatthe injected carbon dioxide stream and associated pressurefront may cause an endangerment to a USDW, the owneror operator must:(1) Immediately cease injection;(2) Take all steps reasonably necessary to identifyand characterize any release;(3) Notify the Director within 24 hours; and(4) Implement the emergency and remedialresponse plan approved by the Director.(b) If the owner or operator obtains evidence thatthe injected carbon dioxide stream,displaced formation fluidsorandassociated pressure frontmay cause anendangerment toendangersa USDW, the owner or operatormust:(1)ImmediatelyCease injectionin a prudent mannerconsidering circumstances.(2) Take all steps reasonably necessary to identifyand characterizethe endangerment posed;(3) Notify the Director or the designatedrepresentative within 24 hoursof becoming aware of theendangerment; andTechnical clarifications.Under some circumstances, an immediate cessation ofinjection could have adverse impacts on other aspects of theoperation.December 23, 2008Carbon Sequestration Council (CCS Contact Group)44 rfvanvoorhees@bryancave.comRule ProvisionsEPA Rule IssueProposed CCS Group RecommendationsBasis for CCS Group Comments(c) The Director may allow the operator to resumeinjection prior to remediation if the owner or operatordemonstrates that the injection operation will not endangerUSDWs.Support the proposed language.Agree with EPA’s rationale.(d) The owner or operatormust notify the Directorand obtain his approval prior to conducting any wellworkover.(d) The owner or operator must notify the Directorprior to conducting any well workoverin response to anycase of endangerment.In critical situations, time spent obtaining approval couldadversely affect the ability to conduct operationsor increasethe level of endangerment.Docket ID No. EPA– HQ–OW–2008–0390

Carbon Sequestration Council 1 December 23, 2008 Attachment B: Comments and Recommendati ons 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 th is 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 disc ussion (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 co mment on the approach to grandfather construction requirements at the

Director’s discretion fo r 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 US DWs because of their

demonstrated success.December 23, 2008

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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 restricti on. 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 CO 2 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 ar e 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 un til the agencies are ready to adapt the Class VI regulations or other requirements as appropriate.December 23, 2008

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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 yi eld 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 stre ams 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 requirem ents. 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

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or Federal Register Cite EPA Preamble Question CSC Response

73 FR 43504 8. Cl ass 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 co nsider the threat of subjecting these pore space owners to CERCLA liability. Their property interests in the CO 2 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 prop osal 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 enda ngerment of USDWs, andwould serve only to prevent the use of otherwiseappropriate GS reservoirs.December 23, 2008

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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 experiencewith 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 propose s 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 pr oposal. 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

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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 se eks 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 mitigateDecember 23, 2008

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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 appropri ate. 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 g eologic settings and rock formation lithologies. EPA Notice 43511. EPA should allow fracturing for stimulation and should set injection pres sure limits to preclude initiating, propagating, or opening avenues of release through fractures transecting the confining zone.

146.88(e) 22. EPA seeks comm ent 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 th e casing/tubing material design strength with the surface injection (compression) system. Do wn-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. A s 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 CO 2 injection wells can be operated in an EOR context without endangering USDWs that are located below theDecember 23, 2008

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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 move ment 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 aquife r 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 refusedto 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 intent ion 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

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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 experienc e 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 generallybe 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 condu cting MITs. EPA should allow operators ad equate 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 necessa ry 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 DirectorDecember 23, 2008

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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 woul d 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 seekscomment 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 meritsof 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 occu r for many years after the project starts.

146.91 35. EPA seeks comment on the frequency of all proposed report ing 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 seek s 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 wouldDecember 23, 2008

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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 requireme nts, 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

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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 appr opriate. 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 w ill serve to provide the Director with the requisite information to make the appropriate determination. The advantage of this approach is that it establis hes clear criteria that an operator must demonstrate before obtaining site closure based upon particular site characteristics and is, therefore, reasonably applicable to any storagesite 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 grou p, in which the Carbon Sequestration Council participated

146.93 39. EPA is requesting comments on theproposed 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

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146.93(b)(2) 40. In additi on, 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 t he 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 financialratings 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 well s. EPA Notice 43522. See response to Question 41 above.December 23, 2008

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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 subjec t 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 request s 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

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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 responsib ility 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 pr oposes that Cla ss 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 bur den without commensurate benefits. The development of AoR, plans, and other parts of the permitting pr ocess 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 signifi cant 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 charac teristics 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, h ence, 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 res ponse to the proposed rule for geologic sequestration of carbon dioxide under the Sa fe Drinking Water Act (SDWA). "Federal Requirements Under the Underground Injection Cont rol (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells", 73 Fed. Re g. 43491-541 (July 25, 2008), Docket ID No. EPA– HQ–OW–2008–0390. We appreciated the extensi on 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 extensi on 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 cl ass 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 ad dress "accounting or certification for greenhouse gas (GHG) reductions." 73 Fed. Reg. 43492, 4349 5 (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 CO 2

EPA’s Proposal would continue to regulate and permit injection of CO 2 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 operato rs of some Class II EOR/EGR wells may wish to use wells for the purposes of production and GS pr ior to the field being completely depleted.” 73 Fed. Reg. at 43502. We recommend that the rule s 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 provid e a “bright line” definition as to the applicableCynthia 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 c onnection 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 c onnection 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 di oxide 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 lang uage 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-stakeholde r 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 th eir views if a consensus can be reached.Cynthia C. Dougherty

December 23, 2008 Page 3

requirements should apply to these wells. We ar e 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 th e 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 specifi cally 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 fr actures), is dealt with in a potentially arbitrary fashion (the 90% of fracture pressure limit), wh ich 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 fa ilure and shear failure only “where appropriate”

because there will be locations where experience or existing in formation 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 wi th 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 sha ll 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 fa ults transecting the confining zone to become transmissive. In no case may injection pressure cause movement of injection or formation fluids in a manner pr ohibited by 40 CFR Part 144.12(a).

Closure Standard

We believe there are three problems with the closur e 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 showingCynthia 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 al ternative language for section 146.93(b) below

because it sets forth detailed criter ia, all of which must be satisfied, to demonstrate that the site does not pose an endangerment to USDWs. The specifi c criteria listed in our proposal will serve to provide the Director with the requisite informati on to make the appropriate determination. The advantage of this approach is that it establishe s 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 standa rd 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 clo sure 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 m onitoring, other site-specific data, and modeling that is reasonably consistent with site performance, that no additional monitoring is needed to assure that the ge ologic sequestration project does not and is not expected to pose an endangerment to USDWs. The Director shall approve closure if the owner or operator demonstr ates, 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 proj ect footprint (CO2 plume and the area of elevated pressure) ; (ii) the estimated locati on of the detectable CO 2 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 en counters 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 theseCynthia 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 addre ssing 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 agen cies 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 regi onal agencies are asked to take on the additional

workload of CO 2 injection, while ensuring careful scient ific review as well as an expeditious processing time, they will require additional trained staff and other resources.

If the nation is serious about controlling CO 2 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 an d managers, must be trained in subjects that will enable them to make prudent permitting, mana gement, and oversight decisions. As momentum grows to begin sequestering CO 2 underground, EPA and states will need to develop new regulatory requirements for CO 2 wells and prepare to review applications and make permitting decisions. Failure to provide sufficient resources will likely cr eate permitting backlogs, resulting in a bottleneck in the overall geologic sequestration effort.

The Ground Water Protection Council (GWPC) estima ted in 2004 that an annual funding increase to $56 million would be needed just to meet the needs of the existi ng UIC program at the state level even without the addition of geolog ic sequestration project permitting. 2 / GWPC has further

estimated that EPA will n eed 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 releva nt issues and to reach significant agreement on how these issues can be a ddressed 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 c ontinuing 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 sc heduled date in late 2010 or early 2011, including development of the requirements to be applied to o il and gas reservoir geologic sequestration that is

2/ GWPC, Class V Resource Needs Su rvey, Summary (September 2004).Cynthia C. Dougherty

December 23, 2008 Page 6

not conducted in conjunction with enhanced oil an d 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 InstituteCynthia 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 CodringtonLetter ID: 0190

Commenter: Robert F. Van Voorhees Organization: Carbon Se questration 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 a ppreciation 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 a nd to reach significant agreement on how these issues can be addr essed 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 combin ation to accurately reflect our shared understanding.

In addition, we are committed to conti nuing the MSD process and to inviting others to participate wi th an objective of devel oping 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 ga s reservoir geologic sequestration that is not conducted in conjunction with enha nced 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. Pleas e see the remainder of EPA's responses to this letter and thos e of other participants of the MS D process for further details. For

additional information on EPA's fi nal regulatory approach, incl uding involving the public in permitting decisions, please see the final rule an d 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 deve lop appropriate regu lations governing CO2 injection for purposes of GS. We agr ee that GS is an important option for the reduction of CO2 emissions, that th e UIC program provides the appropriate framework for the regulation of CO2 in jection, and that UIC regulations specifically tailored to CO2 injection coul d play a vital role in facilitating the development and implementation of GS projects while ensuring that appropriate environmental sa feguards are in place.

1Individual 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 technol ogy 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 inje ction 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 cr itical that any UIC program regulation addressing GS be designed to achieve two goals. First - obviously - such a rule should ensure that CO2 injection is conducte d 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 h ealth and the environm ent. Indeed there has been a long history of successful in jection well operation in the United States, and multiple studies have confir med 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 contrar y, CO2 has been injected for purposes of enhanced oil and gas rec overy (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 adve rse impacts on human health and the

environment.

Individual Response: EPA acknowledges the comment. Pleas e see the remainder of EPA’s responses to this letter for further details. Fo r additional information on EPA’s final regulatory approach, please see the final rule and pr eamble 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

2appreciation of the demonstrated stre ngth 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 in jection; as a result the proposed rule would impose requirements that are substa ntially more elaborat e, burdensome and prescriptive than necessary to protect hu man health and the environment. Because such requirements would impose regulatory burdens that are disproportionate to any environmental benefits they might pr ovide, they would do more to impede and

deter GS than to facilita te its responsible use.

Individual Response: EPA acknowledges that industry has d ecades of experience with well construction and operation. For example, the oil and gas industry has ex perience 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., injecti on, oil and gas production, monitoring). EPA believes that th is experience has led to the de velopment of well materials and construction and operating procedures that are applicable to Class VI wells.

EPA disagrees that the GS requirements are exces sive or are based on an exaggerated assessment of risks and challenges involved in CO2 injection. The Agency be lieves that in jecting 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 belie ves 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 associ ated with long-term in jection of CO2. These requirements include the tailored AoR delin eation process per §146.84, monitoring that is appropriate to GS projects per §146.90, and exte nded 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 wh ether 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 manne r 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 (p erformance-based standards)

Comment: To achieve its goals for this rulemaking - to address the risks of CO2 injection and promote the development of GS - EPA mu st take a hard look at the need for, and practical utility of, each of the requirements it has proposed for CO2 injection. As further detaile d in these Comments, we be lieve that the proposed requirements can and should be stream lined significantly to increase the flexibility of the requirements for CO 2 injection and reduce the unnecessary (and ultimately counterproducti ve) regulatory burdens the proposed rule would impose. We respectfully urge EPA to m odify its proposed regulatory approach

3accordingly.

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 flex ible approach where operators of GS projects would develop and implement site-specific plans for delineating the AoR, testing and monitoring the site, performing corrective actio n, and post-injection site care . EPA believes that the plans— which would be reviewed and approved by the Director and periodical ly updated throughout the life of the project—promote an ongoing dialogue between the operato r and the Director that will encourage use of the most appropriate t echnologies 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 (p erformance-based standards)

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

Comment: We support EPA’s conclusion that the UI C program provides an appropriate framework for regulation of carbon dioxi de (CO2) injection for geologic sequestration (GS). The UIC program gove rns a very wide range of underground injection activities - including the oper ation of thousands of existing CO2 injection wells - and enjoys an extensiv ely 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 c onsiderable practical experience and exceptional technical expertise. While the UIC program is focused on the protection of "underground sources of dri nking water" (USDWs), this seemingly narrow objective is narrow in name only. Infact, 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 h ealth and the environment.

The UIC program currently provides regul ations 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 experi ence with CO2 injection, and should be tailored to address the particular ne eds for this category of injection activity: both the need to prot ect 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 in itial deployment of commercial scale geologic sequestration projects.

4Moreover, the safeguards of the UIC program have been adequate to protect USDWs of all types, including sole source aq uifers, from injection that occurs substantially below those aquifers even where that involves drilling through the aquifer to construct wells that will in ject 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 w ould have been more likely to pose threats of endangerment to dr inking water resources.[FN1]

[FN1: Each year, industria l 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 belo w 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 a nd 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 belie ves that the creation of a new injection well class (VI) unde r the existing UIC Program is necessa ry 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 injecti on of CO2 for GS and adds that the GS regulation tailors the UIC requirements to address the unique issues as sociated 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 impo rtant to establishing a foundation for further advances in the field of CO2 GS. EPA acknowledges the need for regulatory certaint y: the final GS requirements provide a level of certainty by setting forth unique requirement s for GS. These requirements

include: the tailored AoR delin eation 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 regula ting CO2 injection for GS. The Agency plans to collect and review data every six years on GS projects to dete rmine whether the appropriate

5amount and types of information and appropria te documentation are being collected, and to determine if modifications to the requiremen ts are appropriate or necessary. An adaptive approach will allow regulatory development to pr oceed 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 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: B. We Support Continued App lication of the Class II Regul ations to CO2 Injection in the Enhanced Oil or Gas Recovery Contex t and for GS in Oil and Gas Reservoirs and the Creation of "Class VI" Regulations to Address Most Ot her 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 w ould remain under Class II, and a new

classification - Class VI - would be creat ed 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 a void circumstances where EOR operations might be compelled to shift back and forth between Class II and Class VI depending on market conditions. CO2 injec tion for purposes of enhanced oil or gas recovery ("EOR/EGR") has been successf ully regulated as Class II injection for decades, and we agree with EPA th at there is nothing to justify any disruption of the existing regulatory re gime for the thousands of injection wells already in use in these operations. For other GS injection projects outside of oil and gas reservoirs, Clas s 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 ke y 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 operati ons. EPA’s Proposal w ould continue to regulate and permit injection of CO2 for EO R/EGR purposes as Cl ass 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 pur poses of production and GS prior to the field being completely de pleted." 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 consiste nt 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

6EOR/EGR production activities cease and CO2 injection for purpose of GS continues, the risk profile changes, as further discussed belo w. This potential change in risk profile would necessita te additional requirements that are

commensurate with both the hi storic 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 agr eed that the wells used for GS in oil and gas reservoirs that do not meet the criteria of (b)(4) s hould be subject to additional requirements" a nd indicates further that the Group has "tentatively

defined such wells as wells used ‘for geologic sequestrati on in oil and gas formations and where the criteria of pa ragraph (b)(4) are not met.’" There may

be a further recommendation that EPA esta blish 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. Thes e topics are discussed in further

detail below.

In the course of a typical EOR operati on, 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 w ithin the produced oil or recycled for use in other re servoirs; it is not emitted to the atmosphere. Today approximately 90% of the CO2 used in enhanced recovery operations is produced from naturally o ccurring geologic accumulations. Rather than using this naturally occurring CO 2, operators should be encouraged to mitigate greenhouse gas emissions by usi ng 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 th at EOR/EGR operations that include CO2 injection for the purpose of sequestrati on, or what is sometimes called "EOR with sequestration," will remain c overed 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 issu es; the first of wh ich involves the status of Class II CO2 injection wells after oil and gas recovery operations cease. In this situation, EPA should re vise its proposal to retain the regulation of all GS in oil and gas re servoirs in Class II, subject to appropriate requirements as di scussed 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

7leave 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 re gulatory resources and fac ilitating the seamless transition of oil and gas reservoirs to GS service following the completion of EOR/EGR operations. This approach would al so reduce administrative complications or jurisdictional complexities that mi ght otherwise arise and would provide additional regulatory flexibility in s ituations where production may stop and start in response to chan ging market conditions.

Individual Response: The Agency disagrees that wells inje cting CO2 for the primary purpose of long-term storage should be regulated under Cla ss II requirements and ha s 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 re quire that any owner or operato r injecting CO2 for the primary purpose of long term storage obtain a Class VI pe rmit with some special consideration for the fact that they are transitioning from a well not or iginally designed to meet Class VI requirements. The Director has the authority to determine at wh at point a Class VI permit is required for those projects that are transitioning from the primar y purpose of EOR to long term storage of CO2. The final regulation provides a set of technical factors for the Direct or to evaluate in making this determination, at §144.19. EPA believes that this approach provides su fficient protection of

USDWs when there is an increased risk to USDWs as compared to traditi onal Class II operations while allowing for site-specific flexibility.

EPA is developing guidance on transitioning perm its 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 purpos e 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 change s in risk to USDWs from projects, and how the Director may determine whether a project should be regulated within th e Class II or Class VI UIC program. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequest ration.cfm. For more information, please

see the discussion on transition of Class II well s in the preamble to the final GS rule.

In response to the comment on the burden of cha nging regulatory agencies in the middle of an operation, EPA clarifies that primacy is granted to a state, not to a specif ic agency within that state, and states may choose which agency will implement the Class VI program. States may, for example, choose an environmental quality prot ection agency (non-Cla ss 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 federa l requirements for Class VI we lls as required under section 1422 of SDWA. Some states manage all inject ion well classes under Section 1422 and through a single agency, while in other states, Class II pr ograms 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.

8Regardless of the specific Agency the state select s to assume regulatory authority for Class VI operations, the state must obtain primacy for th e 1422 Class VI program. Furthermore, the state may determine that a memorandum of understand ing (MOU) between several state agencies regarding specific projects can f acilitate 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 in jection 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 re quirements 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 pr oposal to receive a Class VI permit," but EPA proposes "to give the Director discretion to carry over or ‘grandfather’ the construction requirements for existi ng wells if the Director makes a

determination "that these wells would not endanger USDWs." 73 Fed. Reg. at 43502. This approach seems backwards: havi ng recognized the problems associated with the application of new well construction standards to existing wells, EPA should recognize that the well construction standards fo r all well classes are designed to ensure that USDWs are not e ndangered. Consequentl y, in the absence of some specific evidence of a constructi on problem that migh t endanger a USDW, there is no basis to question the cons truction of an existing, previouslypermitted injection well, and any "grandfathering" with respect to the Class VI construction requirements shoul d be virtually automatic.

In addition, it is important to recognize that the need and justification for "grandfathering" is not limited to constr uction requirements. There are also proposed Class VI operational and monitori ng 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 suffi cient to prevent endangerment of USDWs. In view of this fact, there should be a regulatory presumption - absent some specific information to the contrary - that con tinued operation of wells already in CO2 service for CO2 injection will al so be protective of USDWs.

The proposed Class VI regulations w ould require a rela tively elaborate demonstration that injected CO2 will rema in isolated from USDWs, and some supplementation of the permit requirements for existing wells may be appropriate consistent with the broad geological cont ainment standards for Class VI wells. To the extent these or other supplementa l requirements are trul y necessary, they

9could and should be imposed through modi fication or supplementation of existing permit conditions rather than through the wholesale application of Class VI program requirements to pre-existing ac tivities already found to be protective of USDWs. Accordingly, we recommend that the Final Rule include a presumption that wells already in CO2 service be allo wed 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 cond itions, subject only to additional requirements as necessary to demonstrate geologic containment of the injected

CO2 stream.

Individual Response: EPA agrees that many Class II well s 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 operat or 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 uni que factors of GS s ites (e.g., increased reservoir pressures associated with large volumes of stored CO2 a nd the corrosivity of CO2 in the presence of water) will result in an increased risk profile, warra nting 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, a nd post-injection site ca re and site closure requirements in the final GS rule. See the discus sion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on these requirements.

The final Class VI regulations re quire that any owner or operato r injecting CO2 for the primary purpose of long term storage obtain a Class VI pe rmit with some special consideration for the fact that they are transitioning from a well not or iginally designed to meet Class VI requirements. The Director has the authority to determine at wh at point a Class VI permit is required for those projects that are transitioning from the primar y purpose of EOR to long term storage of CO2. The final regulation provides a set of technical factors for the Direct or to evaluate in making this determination, at §144.19. EPA believes that this approach provides su fficient protection of

USDWs when there is an increased risk to USDWs as compared to traditi onal Class II operations while allowing for site-specific flexibility.

EPA is developing guidance on transitioning perm its 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 purpos e is oil and gas production, to Class VI, where the primary purpose is long-term storage of large volumes of CO2. The gu idance describes the recommended methods the Director may use to evaluate change s in risk to USDWs from projects, and how the Director may determine whether a project should be regulated within th e Class II or Class VI UIC program. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequest ration.cfm. For more information, please

see the discussion on transition of Class II well s in the preamble to the final GS rule.

10Letter 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 Lim ited to Injection Below the Lowermost

USDW.

The proposed rule limits Class VI injecti on to injection into formations that are below the lowermost underground sour ce of drinking water (USDW). This requirement is not necessary for the pr otection of USDWs and would remove a

substantial number of viable formations from consideration for GS. There are examples of existing CO2 injection we lls (in the EOR/EGR context) that demonstrate that it is possi ble to inject CO2 above th e lowermost USDW without causing any endangerment of USDWs. An ex cellent example is the Salt Creek EOR project in Wyoming, which has a USDW belo w 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 CO 2 sequestration regulation for RMLB out of the context of Rocky Mountain Larami de [?] geology will make it extremely difficult to mitigate the effects of gree nhouse emissions on climate change in the West." Comments of Ronald Surdam, Di rector/State Geologist, Wyoming State Geological Survey (December 2008).

Individual Response: EPA acknowledges that there are lim ited circumstances where injection above the lowermost USDW can be performe d 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 owne rs or operators can seek a waiv er of the Class VI injection depth requirements for injecti on 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 owne rs or operators of Class II EOR/EGR wells transitioning to Class VI injec tion for GS. Additionally, the final GS rule does not categorically preclude or prohibit in jection into any type of formation.

EPA believes that a determination of site-suitability fo r GS (i.e., that subsurface formations will receive and confine injected CO 2) should be made on a site-specific basis. The GS rule, at §146.82, requires the owner or operator to prov ide 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, a nd that USDWs will be protected from endangerment. For additional information on the waiver approa ch, please see the final rule and preamble, as well as EPA's responses to comments on the No tice of Data Availability and Request for

Comment.

11Letter ID: 0190 Comment ID: 24323 Letter Lines: 341 to 360

Comment Code: 1630 1.3.3 RCRA/hazardous waste i ssues (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 pro posing to create a new Class VI well category based on the injection of th e 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 ar e concerned that EPA’s brief discussion of a supposed potential for injected CO 2 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 te chnologies and their extens ive experience with the types of power plant flue gas likely to be sources of CO2 fo r sequestration, we do not believe that captured CO2 stream s should trigger the application of either RCRA or CERCLA. Accordingly, we en courage EPA to dispel concerns that geologic sequestration could be encumber ed with those requirements except possibly through the commingling of a capture d CO2 stream with an actual waste stream, and we are not suggesting that su ch 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 statut es, 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 applicab ility of the RCRA regulations and statute to CO2 streams that are geologically sequestered under the final Cl ass VI UIC well requirements. As a result, EPA has decided to initiate a sepa rate proposed rulemaking sp ecifically to examine the issue of RCRA applicability to CO2 stream s 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 pa rt 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 propose d 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.

12CO2 itself is not listed as a hazardous substan ce 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 th e composition of the specific CO2 stream and the environmental media in which it is stored (e.g., soil or gr ound water). CERCLA exempts from liability, under CERCLA section 107, 42 U.S.C. 9607, certain “f ederally 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 we ll which are outside the scope of the Class VI permit.

EPA adds that promoting the use of GS is outsi de the scope of the GS rule. Rather, the purpose of the GS regulation is to ensu re that, where deployed, GS is c onducted 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 i ssues (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. Ba sed on this premise, the preamble suggests that "EPA cannot make a categor ical 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 ma terial 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 "s olid waste" under this definition unless they are "contained" in a cylinde r or similar container. 54 Fed. Reg. 50968 at 50970, 50973 (December 11, 1989). It follo ws 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 th at supercritical CO2 is not solid or hazardous waste for RCRA purposes and is not subj ect to any RCRA waste determination

13requirements.

Again, the RCRA definition of solid wast e 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 statut ory text suggests that supercritical CO2 should not be considered "solid waste." This reading of the statute makes sense, because RCRA is plainl y 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 prope rties of supercritical CO2 are such that it would immediately vaporize - beco ming an uncontained gas - before it

could contribute to the contents of a landfill. A related practical

consideration is the fact that the haza rdous 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 superc ritical CO2. In partic ular, the toxicity characteristic depends on test methods th at can only be applied to materials that are solids or liquids at standard temperatures and pressures. This is unsurprising, because the toxicity charac teristic was designed to assess the threat waste would have in a municipal landfill disposal scen ario, a scenario that - as already discussed - is inhe rently inapplicable to uncontained supercritical CO2. Accordingly, it makes no legal, policy, or practical sense to treat uncontained supercriti cal CO2 as "solid waste" for RCRA purposes. EPA

should therefore confirm that uncontained s upercritical CO2 is not "solid waste" and is not subject to RCRA wast e 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 st atutory 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 thei r suggested clarifications on the applicability of RCRA to CO2 streams being geologically seques tered. As noted elsewhere, EPA received many comments regarding the applicability of the RCRA regulations and statute to CO2 streams that are geologically se questered under the final Class VI UIC well requirements. As a result, EPA has decided to initia te a separate proposed rulemaki ng 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 pa rt 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 propose d 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.

14Letter 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 na tive brines into USDWs; (2) contain impurities; or (3) cause naturally occurring or otherwise pre-existing chemicals to be mobilized within the injection z one, for example, via the formation of carbonic acid and its leaching effect s. 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 co uld cause endangerment of USDWs." Id.

EPA reiterates some of these concerns under preamble Section 2.J., under the heading "Is injected CO2 considered a h azardous substance under CERCLA?" 73 Fed. Reg. at 43503-04. EPA indicates that CO2, while not itself a CERCLA "hazardous substance," could contain hazardous substa nce 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 injec tion zone formation fluids or USDW formation fluids.) In short, the CERCLA liability concerns flagged by EPA arise out of two basic scenarios: (1) pre-exis ting hazardous substances, or hazardous substance impurities or reaction products moving into or within the injection zone; and (2) these h azardous substances (or displa ced brines) migrating from the injection zone.

EPA also states:

CERCLA exempts from liability cert ain "federally permitted releases" including releases in complianc e with a UIC pe rmit 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 injecti on does not constitute a release under CERCLA. EPA has issued some relevant guida nce in the UIC context. Specifically, EPA has concluded that the emplacement of fluids into an injection zone through an authorized injection well does not c onstitute a "release" for purposes of

15RCRA or CERCLA. See 50 Fed. Reg. 28712 (J uly 15, 1985). EPA relied upon CERCLA’s definition of "release," which requires h azardous substances to make it into the "environment." Under EPA’s interpretation, UIC injection zones do not constitute the "environment," but rath er 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 (o r threatened release) of hazardous substances. Therefore, at least with respect to hazardous substances remaining in the injection zone, one of the key elements fo r CERCLA liability would not be met, regardless of whether the hazardous substa nces 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, signifi cant CERCLA liability concerns could remain with respect to any migration fr om 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 su ch a scenario, or a ny similar context, the mere possibility is a significant con cern 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 ar eas: (1) re lease reporting and (2) cleanup liability. The FPR exemption operates differently in each area, and is more accurately charac terized as two separate exemptions.

Under CERCLA’s release reporting provision s, 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 haza rdous substance from such vessel or facility in quantitie s equal to or greater th an those determined pursuant to CERCLA - Sec. 9602 of th is title, immediately notify the National Response Center....

42 USC § 9603(a). FPR is in turn defi ned to include various types of releases/discharges authorized under any of several federal or delegated state regulatory programs including "(G) any inje ction of fluids au thorized under Federal underground injection control program s or State programs submitted for Federal approval (and not disa pproved by the Administrato r 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 issu e for UIC permittees would simply be

whether the release at issue was an author ized injection of fl uids. If so, the

16release would not have to be reported. Th e FPR for cleanup liability purposes is more complicated.

CERCLA § 107(j) states:

Recovery by any person (including th e 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 sha ll affect or modify in any way the obligations or liability of any pe rson under any other provision of State or Federal law, including common la w, for damages, injury, or loss resulting from a release of any hazar dous substance or for removal or

remedial action or the costs of remo val 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 numb er of other causes of action typically

utilized in hazardous substance contamina tion cases, such as common law claims for trespass, nuisance, negligence, stri ct liability, or "t oxic tort," or statutory claims arising under state groundwater protec tion or cleanup liability

laws.

More importantly, in comparison with th e 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. Th is parallels CERCLA’s liability imposing provisions, which require a release of hazardous substances from a facility "which causes the incurre nce of response costs." This exemption is obviously broader than ju st the FPR itself in that any resulting costs are covered. In other words, the measure of th e scope of the exemption for liability purposes is not limited to whether the rel ease qualifies as a FPR, but rather

whether the costs at issue result from the FPR.

With respect to UIC wells, if the em placement 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 au thorized injection, the costs would not have been incurred. Therefore, the FPR ex emption should apply to the scenarios identified by EPA in the preamble, with the exception of costs incurred due solely to unauthorized rel eases - i.e., releases resu lting from unauthorized injection.

The scope of the FPR exemption in the CE RCLA cleanup liability context has been interpreted narrowly by some courts, but none of the cases involved UIC sites.

17In promulgating the final rule, EPA could provide a more reasoned analysis of the FPR exemption, and dispel any unwarra nted concerns about CERCLA liability. EPA realized over 20 years ago that CERC LA’s FPR exemption needed additional clarification with respect to both rele ase 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 cons idered 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 regul atory 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 deri ved from the source materials or a capture process, and any substances a dded 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 clarif ication, EPA could provide that only the injection under a Cl ass VI permit of streams failing to

meet this definition would fall outside th e scope of the "authorized injection of fluids" unless expressly authorized fo r 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 curt ail efforts to develop CO2GS projects. CERCLA’s far-reaching liability web and th e tremendous costs that can be imposed on parties potentially liable under CERCL A are now well-known. Also well-known

is the reluctance of businesses and invest ors to support projects faced with a potential for liabilities of a CERCLA-scal e. For example, the impacts of CERCLA on the commercial/industrial property mark et in the late 198 0’s and early 1990’s were devastating to many urban centers. To avoid incurring CERCLA liability, property owners and prospective purchas ers simply avoided deals involving

18properties with any pote ntial hazardous substanc e contamination. This

contributed to the so-called "brownfiel d" 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 "gr eenfields" 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 ne gative impacts of potential CERCLA liability, EPA and many st ates have gone to great lengths over the last ten years to alleviate liabilit y concerns and encourage brownfield development projects. Similarly, EPA s hould 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 th e opportunity in this rulemaking to alleviate unwarranted CERCLA liability concer ns to the greatest extent possible.

Even more troubling than the potential negative impact on the investment community is the threat of subjectin g hundreds, thousands, and even more numerous pore space owners to CERCLA lia bility. Their propert y 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 remedi ation - 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 wi thout even beginning to consider how the willingness of pore space owners to pa rticipate might be obliterated by the

uncertainties of CERCLA liabilit ies hanging over their heads.

In short, EPA needs to seize the opport unity to dispel the specter of CERCLA liability raised in its preamble by deve loping appropriate lan guage to provide the clarity and assurance needed to prom ote 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 cont ain 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 sulf uric acid). Whether such subs tances may result in CERCLA liability from a sequestration f acility 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 un der the authority of th e SDWA. To the extent the commenter is seeking interpretations of CE RCLA and its related pr ovisions, such as the

19definition 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 remedi al response is necessary. Although EPA anticipates that the need for emergency or remedial actions at GS sites wi ll be rare, the GS rule requires, at §146.94, that emergency and remedial response plans be deve loped and updated to address such events and that owners or operators demonstr ate 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 regu latory requirements

under Part 146 for Class VI wells and the Dire ctor has approved site closure pursuant to requirements at §146.93, the owner or operato r will generally no longer be subject to enforcement for regulatory noncompliance. Furtherm ore, 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 ce rtain circumstances. For example, an owner or operator may be held liable for regulatory noncompliance even afte r site closure was approved if the Director relied on erroneous information (e.g., erroneous modeling data) provid ed by the owner or operator when approving site closure.

Separate from EPA's authority to enforce regul atory compliance, an owner or operator may be subject to a §1431 response orde r even after proper site cl osure is approved under §146.93. Under §1431 the Administrator may require an ow ner 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 pres ent an imminent and s ubstantial endangerment to the health of persons, and the appropriate Stat e and local authorities ha ve not acted to protect the health of such persons. Th e action may include issuing admi nistrative orders or commencing a civil action for appropriate relief against the ow ner 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 ope rator may remain liable under tort and other remedies, or under other federal statutes includi ng, 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 SD WA 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 outsi de the scope of the GS rule. Rather, the purpose of the GS regulation is to ensu re that, where deployed, GS is c onducted in a manner that protects USDWs from endangerment.

Letter ID: 0190 Comment ID: 24326 Letter Lines: 633 to 690

20Comment 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 Regulati ons for GS Are Not More Stringent or Prescriptive than Necessa ry to Protect USDWs.

EPA has recognized that it has two goals for the proposed rules for geologic storage of carbon dioxide: the protecti on of underground sources of drinking water [FN2/] and the promotion of th e development of carbon capture and storage.[FN3/] EPA Administrator Stephe n Johnson noted when he announced the proposal that ""[t]oday's proposal paves the way for technologies that would protect public health and he lp reduce the effects of climate change. With proper site selection and management, geologic se questration could play a major role in reducing emissions of carbon dioxide into th e 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 de signed to facilitate - not delay or discourage - the successful commercial-s cale 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 ge ologic site charac terization, fluid movement, area of review (AoR) and corrective action, we ll 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 Gr oundwork for Promising Technologies to Help Mitigate Climate Change" (July 15, 2008), http://www.epa.gov/safewater/uic/wells_se questration.html ("EPA is proposing a rule that supports promis ing technologies to preven t industrial emissions of carbon dioxide. Secure, long-term undergr ound 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 c oordinating with the Department of Energy on carbon sequestration research and development."); EPA Press Release, "EPA To Develop Regulations for Geol ogic Sequestration of Carbon Dioxide" (October 7, 2007) Id.] [FN4/: EPA Press Release (July 15, 2008).]

Unfortunately, in its effort to ensure pr otection of USDWs, EPA has exhibited a zeal that could materially impede, over burden, and effectively stigmatize GS. The preamble to the proposed rule repeat edly overstates the ri sks posed by CO2 injection while systematically underst ating the extent of knowledge and experience industry and regulators have gained through decades of practical experience with a wide range of injection well operat ions. As a result, the preamble presents an exhaustive review of every imaginable risk with respect to

21CO2 injection, but fails to disclose that many of these theoreti cal 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, bu t 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 CO 2 is injected underground. After all, there are already thousands of existing CO2 injection wells in operation that have injected hundreds of millions of t ons of CO2 largely without incident. Rather than provide appropriate contex t for the development of Class VI regulations, however, the proposed rule gi ves the impression that GS is an adventure into entirely uncharted seas . The proposed rule - having started by framing the issues in this way - then em ploys a regulatory approach that errs on the side of including excessively prescr iptive, 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 ha s, as a result, developed a ne w well class with requirements tailored to address the unique challenges posed by GS and potenti al risks associated with longterm injection of CO2. These requirements in clude the tailored AoR delineation process per §146.84, monitoring that is appropriate to GS projects per §146.90, and ex tended post-injection site care per §146.93.

EPA acknowledges that industry has decades of e xperience with well construction and operation. For example, the oil and gas industry has experi ence drilling and cementing wells in very deep formations, in a variety of environments (e.g., hi gh-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 we ll 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 wh ether 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 manne r 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

22Comment: 1. The Proposed Class VI Requirements Are Far More Burdensome than Necessary

to

Protect USDWs.

As the preamble acknowledges, the actua l human health and ecological risks associated with GS are relatively remo te and can be addressed effectively through measures implemented to prot ect USDWs. 73 Fed. Reg. at 43497-98. Unfortunately, having started with an ex aggerated sense of the risks involved and an inadequate recognition of th e value of existing regulatory and operational experience relevant to CO2 in jection, the proposed rule seems to proceed from the premise that the most strict UIC regulations in existence - those for hazardous waste injection - shoul d 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 wa ste 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 invol ved; these are not issues that the requirements for hazardous waste inject ion are particularly well suited to

address.

The more logical starting point for devel opment of the Class VI regulations is the Class II regulations. As the propos ed 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 Cla ss II regulations - as applied to CO2 injection - are adequate to protect USDWs. This is certainly true with respect to the basic construction, operating, m onitoring, and mechanical integrity testing requirements for injection wells; after all, what "wor ks" 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 su ch as well construction and mechanical integrity testing should be any differe nt than the Class II requirements.

Unfortunately, the proposed Class VI requi rements are far more stringent than the Class II requirements, a fact that cr eates a need to "grandfather" Class II CO2 injection wells that remain in se rvice 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 require ments proposed for Class VI wells are even more comprehensive and more strict than those for hazardous waste injection

wells. While some of these more burdensom e requirements are legitimately related to concerns about the mobility of CO2 or the anticipated scal e of GS operations, many - as discussed in Part III of these comments - are not.

23Individual Response: EPA disagrees that the GS requireme nts are excessive or are based on exaggerated risks; the Agency believes that in jecting large volumes of CO2 for GS poses unique challenges that, if not properly managed, could endanger drinking water s ources or have other adverse impacts. EPA believes that caution is wa rranted 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 CO 2. These requirements include the tailored AoR delineation process per §146.84, monitoring that is appropriate to GS projects per §146.90, and extended post-injecti on site care per §146.93.

EPA believes that the nature of CO2 injection for long-term storag e is different from Class II CO2 injection for ER, and that tailored require ments for Class VI wells are appropriate and necessary to protect USDWs fr om 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 th e unique nature of CO2 GS (i.e ., very large volumes, very long time-periods, and reservoi r 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 ris k, don't stigmatize CO2

Comment: 2. Rules that Stigmatize GS or Burden it Ex cessively 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 th e 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 - inherent ly magnify the impression of risk and could thus stigmatize GS and discourage i nvestment in GS projects. EPA should recognize that "more regulation" - particul arly 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 pe rception when it come s to the siting and permitting of needed infrastructure, and believe strongly in the need to ensure that the public has accurate info rmation. 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 issu es and concerns ca n be addressed. Similarly, we urge EPA to avoid the im position of regulatory requirements that are so disproportionate to the risks invol ved that they may do more to incite than address public concerns. To this e nd, EPA should scale back its regulatory

24requirements 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 re gulations 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 shoul d recognize the importance of the messages that it sends the financial worl d through the regulations it imposes.

Permanent storage of CO2 can be accomplis hed safely and without harm to the environment as long as we apply the right knowledge base, detailed site-specific information, technical expertise, and s ound 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 abou t the nature of CO2 and the actual magnitude of the risk s associated with GS. It is also

critical that EPA strike an appropriate balance by addressing the risks associated with GS without creating a regi me 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 ha ve other adverse impacts. However, with proper site sele ction, 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 expect s the tailored permitting, siting, construction, operation, monitoring, and post-injection site care re quirements in the GS rule to prevent leakage from injection formations and protect USDWs.

EPA does not believe that the tailored require ments will create a negativ e 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 c onfidence 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. Pleas e 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

25Comment 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 appropria te use of GS to reduce CO2 emissions, the regulations should be designed to allo w 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 basi s as particular geologic site conditions wa rrant, without the need to apply prescriptive criteria that - while perhaps necessary to endure protection of USDWs in some cases - would arbitrarily disqualify so me sites that would in fact be appropriate for GS. This does not mean th at regulation need be lax; it simply means that regulation must be flexible , and that rigid cr iteria should not substitute for performance-based standard s 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 withsufficient permeability, porosity, thickness and lateral extent and a lowpermeability confining zone with sufficien t thickness and lateral extent to protect overlying USDWs. 73 Fed. Reg. at 43505. These are familiar and appropriate geologic siting re quirements for injection we ll 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 s uggest the need for overly-elaborate analysis of extraneous issu es, and the rule text propos ed 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 s hould go no farther than necessary to prevent endangerment, and s hould eliminate any apparent discretion to impose siting requirements that ar e not necessary to protect USDWs.

Individual Response: The final rule does not preclude injecti on 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 inject ion of potentially large volumes of CO2 for longterm storage. The regulation provide s flexibility to owners or operato rs to select appropriate sites and target formations (under §146.82), well cons truction specifics (unde r §146.86), and injection procedures provided the owner or operator can de monstrate that the injection and storage will not endanger USDWs and that minimum requirements for the site are met.

26Letter 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 ge ologic 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 co ntext, and requirements for unnecessarily elaborate analysis would serve only to bur den 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 de monstrating that such risks are modest and easily addressed through appropriat e injection pressu re 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 aci d, the resulting carbonic acid is only weakly corrosive and - as experience with the injection of extremely corrosive

hazardous wastes demonstrates - cannot r easonably be expected to cause any breach of containment that would endange r 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 siti ng 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 reac tions 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 fl uid 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

27injection pressure due to reduced porosity, in particular, can lead to fracturing of the confining layer and potentially allow fluid movement outside of the injec tion zone. Losses in injectivity because of geochemical reactions may also re quire additional injection wells and further penetrations in the confini ng layer that can become path ways for fluid migration.

EPA disagrees with the comment that the com position of the CO2 stream is not important. Information about the composition of the CO2 st ream 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 im portant consideration. Wh ile increasing storage capacity is not the intent of the UIC requireme nts, 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 unaccep table fluid movement and improve USDW protection from endangerment.

Finally, EPA disagrees that consid eration of local and regional se ismicity is not important. The site characterization provisions in the GS ru le, including a review of the local and regional geology, and detailed review of any known or potenti al seismically active te rrain in the vicinity of a proposed GS site are necessary to minimize the potential for induced seismic events or the reactivation of faults, which ar e a known potential risk associ ated 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 Fina l Rule should require, or allow the Director discretion to requi re, 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 necessa ry to specify one or more additional formations as part of the a confining syst em 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). Cons iderations 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 defi nition, a requirement for additional confining zones would therefore be a requirement for redundant geologic

28containment: it would never be necessar y for the protection of USDWs. By allowing the Director discre tion to impose such a require ment, 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 evalua tion of additional geologic formations just because they are there, perhaps in the hope that a dditional 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 pr oposed rule would invite a "belt and suspenders" approach that would unnecessarily burde n permit applicants and signal unwarranted concern a bout the risks and uncertainti es associated with CO2 injection. Under the UIC program, protec tion 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 c onfining and containment zones would be unprecedented. No such requi rement exists in the UIC program,

even in the context of hazardous waste injection. Nor does su ch a requirement apply in any of the countries where GS projects are currently underway (including Norway, Canada, Australia and Al geria). EPA should not single out GS for heightened and substantially more ri gorous requirements than would apply in other contexts. To do so would signal a disproportionate c oncern about the injection of CO2 that simply is not warranted on the merits.

Individual Response: EPA retains the requirement to iden tify additional containment/confining zones, if required by the Di rector, as proposed (§146.83(b)). EPA acknowledges that such additional zones may not be needed in all circumst ances and clarifies that this requirement is at the Director's discretion, based on his or her understanding of a part icular 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 protecti on. These layers could further impede vertical fluid movement and al low for pressure dissipation, and also provide additional sites for monitoring, mitigation, and re mediation. The Agency's decision is supported by commenters representing states, water associati ons, and an electric utility who assert that these requirements promote a flexible, risk-base d, site-specific approach to characterizing and permitting a site for GS projects, and are intende d 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 th is 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

29Comment 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 Corre ctive Action Requirements

We support the use of comput ational 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 acti on to address risks presented by artificial penetrati ons such as abandoned boreholes. The use of such modeling is already well-established in the cont ext of oil and gas exploration and production and has been used in the UIC pr ogram 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 s upport and agrees that predicting the complex, multiphase, buoyant flow of the CO 2, co-injectates, and compounds that may be mobilized due to injection requires the sophistica tion of computational models, as required at §146.84(c)(1). that may be mobilized due to injection requires th e sophistication of computational models. Models can predict CO2 fate and transport, as well as changes in formation pressure, in three dimens ions, as a function of time in or der to delineate the subsurface storage site and the AoR. Models can account fo r site-specific and pred icted operating conditions as well as geologic heterogeneitie s and potential migration through fa ults, fractures, and artificial penetrations.

Letter ID: 0190 Comment ID: 24334 Letter Lines: 908 to 947

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling 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 defi nition goes on to suggest that the AOR is to be "based on computational mode ling 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" pe titions shows, it is rarely necessary to attempt to model chemical change s in the injectate plume; instead conservative modeling of transport should typically be sufficient by itself to

30show that USDWs will not be endangere d. Where this is the case, it is containment of the injectate plume - rath er 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 m odel "the chemical properties of all phases of the injected carbon dioxide str eam" as the proposed rule suggests. Such modeling should be required only to th e 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) m odeling may be sufficient and even preferable for this purpose. A quest for greater precision would not guarantee greater confidence in modeling results, and could effectivel y require a less conservative - and thus potentially le ss 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., "m ay be impacted by the injection activity") is not clearly limited to imp acts of the injecti on 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 comput ational models, as required at 146.84(c )(1). Models can predict CO2 fate and transport, as well as changes in formation pr essure, in three dimensi ons, as a function of time in order to delineate the subsurface storage si te and the AoR. Models can account for sitespecific and predicted operating conditions as well as geologi c heterogeneities and potential migration through faults, fractures, and artificial penetrations.

EPA acknowledges that fine precision may not al ways 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 pr otective modeling approach. EPA an ticipates that the owner or operator, in consultation with th e Director, will choose the model th at is most appropriate for a particular GS project, and that th is dialogue is a key factor in assu ring that the GS site is modeled (and eventually operated and trac ked) in a manner that protects USDWs from endangerment. EPA encourages and expects owners or operators to use the best multiphase, computational

models available.

31Letter 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 progr am requirement. Given the potential scale of GS operations, EPA has proposed requirements for a corrective action plan contemplating a phased implementa tion of corrective act ion. In general, this approach is prudent and practic al, providing a rigorou s approach to corrective action while reducing regulatory burdens by permitting a phased implementation of corrective action requirements.

Individual Response: EPA acknowledges the commenter’s s upport 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, avoi ding delays in project start-up, allowing for use of future, improved corrective act ion 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 fre quency (seeking comment)

Comment: 3. AOR Reevaluation

The proposed rule requires periodic reev aluation 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 significan t 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 injec tion 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 in formation becomes available that is materially inconsistent with assu mptions 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 requirem ents, and that these reports include an

32assessment 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, injecti on rates, annular pressures for each injection well, the result s of any mechanical in tegrity tests conducted during this time period, available s ite integrity monitoring results, the extent of the injected CO2 and th e pressure front based on current

data.

Update site operations as appropr iate and site modeling results annually, or at a frequency acceptabl e to the Director, to reflect current data. Compare the updated re sults to the previous results. Identify and explain to the Direct or 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 th e 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 wo uld be unnecessary.

Individual Response: EPA agrees that site-specific factor s, 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 m onitoring and operational co nditions 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 fr equency 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 discre tion 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

33Many 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 ar e sufficient to ensure that injected fluids cannot escape from the intended injection zone via the injection well borehole. The proposed rule would neverthe less impose substantially more costly well construction requirements resembli ng those for Class I hazardous waste injection wells. The Proposed Rule specifi cally cites the buoyancy of CO2 as the justification for these requirem ents. See 73 Fed. Reg. at 43509.

The buoyancy of CO2 in no way justifies th e additional construction requirements proposed. The reason for this is straight -forward: by far the greatest driving force for fluid migration along an inj ection 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 injec tion 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 mi gration. At the injection well, however, the induced pressure gradient caused by the injection activity would so dwarf the impact of buoyancy as to render th e latter insignificant. Accordingly, it would be unreasonable to suggest that buoyancy justifies significantly more demanding injection well construction requi rements 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 ha s proved effective in the context of the Class II program, and leaves permit-wr iters 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 labor atory studies that eval uated 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 show ed evidence of cement alteration (carbonation) due to exposure from CO2. (The study was not able to determine whether the alteration wa s 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

34overlying 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 CO 2 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 require ments at §146.86. For example, seismic surveys at Sleipner showed that CO2 had migrated to the top of th e 200 to 300 meter thick formation as early as three years after injection began. Th e overall behavior of CO2 at Slei pner 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 volum e 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 th e primary purpose of long-term storage is sufficiently different from Class II ER operations and warrants tail ored 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 di fferent, with Class VI injection operations involving large volumes of CO2 and likely having hi gher 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 requi rement 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 partic ularly deep) where such a requirement would be unduly burdensome and inappropriate . Accordingly, the need for surface casing to extend all the way through the ba se of the lowermost USDW should be left to the discretion of the permit write r rather than being predetermined in

the text of the rule.

Individual Response: EPA disagrees that the requirement s hould be deleted and believes that the regulations allow appropriate flexibility re garding the surface casing. The GS final rule at §146.86(b)(2) requires that surface casing extend th rough 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 pr otected. EPA notes that there are many potential ways to meet the requirement, such as the use of stag ed cementing. EPA is developing guidance on the construction of Class VI wells. This guida nce will be available on EPA’s website at

35http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

EPA recognizes concerns regardi ng construction of Class VI wells where the lowermost USDW is very deep. To further address comments on d eep 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 opera ting under injection depth waivers must comply with additional construction require ments to ensure that wells used to inject above or between USDWs are protective. See the discussion of the wa iver 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 requi rement for the long-string casing to be cemented to the surface. Such a require ment - 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 pe rformance 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 cem enting 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 an d 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 additi onal 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/gr oundwater/uic/wells_se questration.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 in jection through a tubing and packer to facilitate continuous monitoring of a pr essurized annulus. Wells designed with tubing and packer effectively provide tw o barriers, both of which must be breached before injectate could leave th e borehole. At the same time, this design permits a proven method of monitori ng that would permit detection of a breach in either barrier so that repairs can be made before both barriers fail.

36And a requirement to maintain positive pressure on the annulus, rather than always maintaining the annulus pressure in excess of the inject ed fluid pressure in the injection tubing will be sufficien t as CO2 is not hazardous waste.

Individual Response: EPA agrees that the use of tubi ng and packer in accordance with §146.86(c) will offer the best multiple-barrier pr otection 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 co rrosion-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 s uggests 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 wa ter. This distinction is critical from a practical standpoint, because injected CO2 streams would at least generally be "dry" (i.e., dehydrated) and ther efore non-corrosive. Once injected, the "dry" CO2

would come into contact with naturall y-occurring water in the subsurface, creating carbonic acid. Howeve r, an injection well would inject CO2 far more rapidly than the CO2 could mix with wa ter, creating a CO2 plume that would immediately displace water away from the point of injection. While some residual water saturation would remain, the potenti al 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 resi st a severely corrosive environment.

Class II experience with CO 2 injection supports this conclusion. Corrosion is sometimes an issue for injection wells us ed 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 wit hout the need for co rrosion-resistant construction or the occurrence of corrosion-related problems.

37Well construction requirements under the UI C program generall y require that operational conditions and the nature of fo rmation fluids and proposed injectate be considered in well construction, and th ese general requirements have served well. Thus, while there may be some Cla ss VI CO2 injection scenarios in which corrosion-resistant materials may be requi red, there is no technical basis for any general presumption that they ar e 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 inje ction well, not the ultimate duration of the GS program. The potential for l onger 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 m odeling study or other informati on 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 ce ment corrosion. Several st udies including field, laboratory, and modeling studies ha ve found that pH drops in the formation fluid, indicating at least partial mixing of the carbon dioxide and form ation water (Kaszuba et al, 2005; Kharaka et al, 2006; Birkholzer et al, 2008). Th e risk of creating acidic fluids that could come in contact

with well materials and cements is addresse d 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 proj ect. GS projects are anticipated to have long life span s 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 th e GS project, but they must be constructed such that US DWs 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 ri sk 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 moveme nt 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 Prio r to Injection Well Operation

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

38comments, our principal concern is th at the logging, sampling and testing requirements of the proposed rule ar e overly rigid and pr escriptive. 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 propos ed 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 pr ior 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 tes ting clearly should not be necessary where there are multiple other injection we lls 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 requireme nts be tailored to the circumstances involved so that that costly and dup licative logging, sampling and testing requirements can be avoided.

Individual Response: EPA believes that the logging and testi ng requirements in the GS rule are appropriate and necessary. The requirements at §146.87 stem from existing knowledge and practices in place for other inj ection well classes and within th e oil and gas industry, and are tailored to the special characteris tics of CO2 injection for GS.

EPA is developing guidance on monitoring and tes ting that will describe recommended tests and procedures to assist owners/operators and Di rectors 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/ground water/uic/wells_sequestration.cfm.

EPA clarifies that §146.87(b) pr ovides 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 po ssible 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 authorit y to require the owner or opera tor 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

391. Injection Pressure Limitations

We support the discussion and recommendati on 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 zo ne, the limit is site-sp ecific and not arbitrary. EPA emphasizes that injection pressure limits ar e important to protect against fracturing of the confining zone, and that the requ irement at §146.88(a) that the pressure in th e 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 Dire ctor determines, based on a review of the information collected as part of site characterization, th at a lower injection pr essure 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 pressuri zed 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 shoul d exceed injection tube pressure was

introduced in the context of hazardous waste injection, where it reflected an extreme sensitivity to even the most re mote possibility of a release of hazardous waste (the requirement was desi gned 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 detec tion of casing leaks whether or not annulus pressure exceeds injection pressu re. Similarly, any significant pressure differential between in annulus and inj ection 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 in jection pressure could - depending on the site conditions involved - do more to limit than enhance the sensitivity of leak detecti on. Consequently, the determination of annulus pressure should be left to the permitting process, without any

40presumption 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 in jectate 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 th e commenter suggests, must be considered in maintaining annulus pressure and that fluid dens ity should be considered when establishing an annulus pressure value at the surface. EPA also be lieves this requirement is appropriate for Class VI wells given the potential high volumes and superc ritical 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 mechani cal integrity monitoring (seeking comment)

Comment: 3. Continuous Monitoring

As already indicated, we support conti nuous annulus and injection pressure monitoring for leak detection purposes. C ontinuous 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 contempl ated) impractical. There is ample UIC program experience demonstr ating that continuous mon itoring of annulus fluid volume is not required for any purpose. Fo r leak detection, pressure monitoring - with periodic records of annulus flui d additions and withdrawals - has proved

to be sufficient.

Individual Response: EPA acknowledges the comment and ag rees that continuous pressure monitoring to demonstrate intern al mechanical integrity requir ed 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 supe rcritical 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 be lieves that knowing the annulus fluid volume

added is sufficient to meet the intent of the re quirement. The final GS rule requires that owners or operators use continuous reco rding devices to monitor injecti on 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 flui d 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-o ff 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 inte nded 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 justif ication to require the use of down-hole shut-off valves in the CO2 injection cont ext. Class I hazardou s waste injection wells are not required to have down-hole au tomatic shut-off valves, and there is no basis at all to suggest that CO2 in jection entails highe r risks warranting such costly and problematic measures.

Individual Response: After evaluating the risks and benefi ts of down-hole shut-off systems and considering additional research, EPA will not re quire 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 owne rs 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 o ffshore Class VI wells pr esent unique construction and operational conditions, including isolation from shorelines and the need to construct wells through the water column and the subsurface, wh ich 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 instal l 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 ty pically be used to inject corrosive fluids or will always be in contact with corrosive c onditions in the injection

42zone. A general requirement for corrosi on 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 risk s corrosion would present. In particular, the proposed rule would require that in jection wells be designed and constructed fo r their intended service. This requirement would address the potential for corrosion even if (as we recommend) the burdensome and unnecessary provisions expre ssly requiring use of corro sion-resistant materials is excised. In addition, the requirements for a tubing and packer design would protect against corrosion l eaks, both by providing secondary containment of the injectate and by permitting continuous annulus pressure monitoring (also required) to ensure that corrosion leaks c ould be detected and repaired before both layers of containm ent would be breached.

Individual Response: EPA disagrees with commenter's asse rtions that corrosion monitoring is unnecessary or excessive. CO2 in the presence of water (including wa ter with NOx, SOx, and H2S impurities) can be corrosive to well mate rials 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 forma tion, must be considere d. While the construction requirements at §146.86 were designed to protect against corrosion, EPA believes that multiple barriers against corrosion-related failures, incl uding construction and monitoring requirements, are necessary in order to prot ect USDWs from endangerment.

Several laboratory studies a nd a limited number of field studies have investigated and

characterized the effects of carbonic acid on well materials. La boratory studies (e.g., Kutchko et al., 2007; Kutchko et al., 2008; Ak ervoll, 2005) consistently iden tify alterations (typically carbonation) of cement as the result of interac tions between cement and CO2-saturated brine.

Currently, there are only a few analyses of cemen t from wells that have been in prolonged

contact with CO2 in actual fiel d (down-hole) conditions. Evaluati on of cement from a well at the Scurry Area Canyon Reef Operator s Committee (SACROC) site s howed alteration, but did not show degradation that compromise d the structural integrity of th e 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 addre sses the effects of corrosion of st eel tubing and pipes. Lopez et al. (2003) noted that 60 percent of oilfield failures are re lated 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/de gradation is an ongoing re search area. Few field43based studies have been completed to date. A lthough the laboratory and field studies currently available suggest that corrosion pr oblems 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 re strictions are not necessary to protect USDWs and would serve only to prec lude the use of what might otherwise be appropriate CO2 storage reservoi rs. 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 ot her factors - could not reasonably be expected to serve as sources of drinki ng water, we support the appropriate use of aquifer exemptions to facilitate GS.

Individual Response: EPA agrees that it is not appropriate to set a mi nimum injection depth for GS projects. EPA believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confin e injected CO2) should be made on a site-specific basis. The GS rule, at §146.82, requires the ow ner or operator to pr ovide 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, a nd that USDWs will be protected from endangerment.

EPA acknowledges that there are limited circum stances where injectio n above the lowermost USDW can be performed in a manner that protec ts USDWs, as long as appropriate protections are in place. The final GS rule at §146.95 establis hes a process by which owners or operators can seek a waiver of the Class VI injection de pth requirements for in jection into non-USDW

formations above and/or between USDWs. The waiver approach requires the submission of extensive, site-specific information (in conjunc tion with the permit appl ication submission) to demonstrate that injection of CO2 into a non-US DW that is above or between USDWs can be done in a manner that is protective of USDWs. Th e requirements are designed to ensure that the owner or operator, the Director, and the Regional Administrator cons ider, on a site specific basis, the implications, benefits, and challenges associat ed with GS and ensuring water availability and

44USDW 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 im pact on human health or ecosystems (seeking comment)

Comment: 7. Tracers

We strongly oppose any requirement for th e use of tracers, including any such requirement that could be imposed at the discretion of the Director.

There are at least two funda mental issues with respect to tracers. First, tracers are unlikely to enhance the protecti on of USDWs. This is true not just because the Class VI regulations are de signed to minimize the likelihood of the kind of leakage tracers would ostensibly he lp detect, but because - even in the

event of such a leak - tra cers are not likely to be esp ecially 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 occu r in the surface environment than in the deep subsurface.

A final consideration is perhaps the mo st 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 extraordinar ily unlikely to occur.

Individual Response: EPA believes that, in some circumst ances, tracers can be an important component of a multifaceted approach to mon itoring GS projects. However, the Agency recognizes that tracers may not be appropriate in all GS project s. For this reason, EPA does not require the use of tracers at all GS sites; however, the Director ha s discretion to require their use

if he/she determines that the use of tracers could improve mon itoring of the site and enhance USDW protection from endangerment.

EPA disagrees that using tracers, where appropri ate, would overstate th e danger of CO2 or GS. Rather, EPA believes that providing the public wi th 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 pr ojects and GS technology in general.

While the intent of the GS regulations is to prevent leaks of CO2 to USDWs, EPA clarifies that

45all of the protective components of the GS regulation, including a comprehensive monitoring program per §146.90 (which includes testing of th e 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., Phel ps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005) found that tracers can pr ovide useful CO2 monitoring information at injection wells both at depth and at near-surface locations. At Fr io, tracers enabled quantification of CO2 plume behavior and provided a techniqu e for model validity tes ting (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 documenta tion 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 Te sting (MIT) Requirements

The proposed rule suggests that "MIT requirements for GS wells should be tailored to address the unique proper ties of CO2, specifically its buoyancy and potential corrosivity." 73 Fed. Reg. at 43513. As previously discussed, however, the buoyancy of CO2 is a rela tively trivial factor in re lation to the cone of influence created by injection pressure during injection, a factor that makes buoyancy virtually irrelevant as a driv ing force for upward migration through the injection well borehole during the operational life of a GS well. Accordingly, there is no basis to su ggest that the buoyanc y of CO2 is a significant factor to consider in esta blishing mechanical integrity testing requirements for GS wells. Similarly - as al so previously discussed - CO2 is not corrosive and cannot be expected to cause substantial corrosion problems for the injection well (including down-hole cem ent) 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 reas on 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. EP A has identified buoyancy as one of the unique characteristics of CO2 that warrants sp ecial consideration. The Agency believes that buoyancy of the injected CO2 coupl ed with other characteristics of GS operations, including the large injection volumes and timefra mes 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.

46Supercritical CO2 has a lower density than the na tive formation fluids in the target injection formations typically anticipated for GS. On ce injected, the more buoyant CO2 will have a tendency to migrate upwards. This expected moveme nt 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 attr ibuted 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 in jection zone preferentially throu gh fractures. Such migration could occur through conduits in th e injection wellbore as well as in the target formations. In the case of GS, any cracks or fractures in the cement casi ng for a GS injection well would also serve as conduits for upward migration of more buoyant flui ds. External MITs, whic h test for movement along the borehole, are therefore appropr iate requirements for GS wells.

EPA disagrees that the MIT requirements for Cl ass VI wells are excessive. MITs are a longstanding and proven method of pr oviding early warning of potential problems in the injection well system before they lead to leak age and/or endangerment of USDWs.

EPA also disagrees that corrosivi ty is not a concern. While some studies of cement performance have shown encouraging results, other informa tion 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 endang er USDWs. Although laboratory and field studies suggest that corrosion problems ma y 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 injecti on 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 requi rements 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 t hose that inject non-co rrosive 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 in jecting CO2. However, EPA believes that significant operational differen ces 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 pr essure 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 mo re 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.

47Letter ID: 0190 Comment ID: 24352 Letter Lines: 1285 to 1287

Comment Code: 4520 2.5.1 Continuous internal mechani cal integrity monitoring (seeking comment)

Comment: As already indicated, we support the requi rement for continuous injection and annulus pressure monitoring as a means to ensure "internal" mechanical integrity. With regard to "external" mech anical 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, inst ead of periodic testing (which is required for most other types of deep injecti on wells), is appropriate because the potentially corrosive nature of CO2 injectate streams in th e presence of water enables th e immediate identification of corrosion-related internal mechanical integrity problems that could lead to significant well problems and failure. The final GS ru le 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 frequenc y 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 describe d 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 pr oblems in the injection well system.

EPA clarifies that the regulations provide the Director discreti on to require additional methods or, with the Administrator's approval, to appr ove the use of alterna tive MIT methods based on specific information about the s ite 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 extern al mechanical integrity at le ast 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 protecti on of USDWs from endangerment given the unique nature of CO2 GS relative to other injection operations, including the pote ntial 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 ch anges, the temperature and pressure effects associated with injecting supercritical CO2, and the buoyant nature of th e injected CO2. Because of the unknown long-term effects of CO2 GS, EPA chose a more cons ervative initial approach in the early stages of deployment for GS.

48In addition, a comprehensive review conducte d by EPA of MIT results from 1993 to 1998 found that Class I wells injecting corrosi ve fluids fail MITs at rates two to three times higher than those that inject non-corrosive fluids (USEPA 1999). Given the potentia l for CO2 to be corrosive (e.g., in the presence of water or aqueous formation flui ds), there is a potential risk factor for MIT failure and, for this reason, EPA be lieves that the tailored MIT requi rements in the final GS rule are appropriate.

EPA adds that it is using an ad aptive approach to regulating GS. The Agency plans to collect and review data every six years on GS projects, including MIT da ta, to determine whether the appropriate amount and types of information a nd 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 indicat es 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 precis e "prediction" of actual fate and transport that can or should be "verifie d" on the basis of el aborate, 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 pressu re fall-off tests provide ample data to validate the results of modeling. Th e additional monitoring requirements proposed in the GS context go beyond wh at is required for Class I hazardous waste injection wells; these requireme nts are excessive and unnecessary.

Individual Response: EPA agrees that good site selection a nd modeling are crucial elements of a successful GS project, but disagrees that this is an effec tive substitute for rigorous site monitoring, including pressure monitoring. EPA believes that pressure monitoring in the injection zone is necessary to track the development and moveme nt of the pressure front and CO2 plume. Monitoring can also identify need ed remedial actions, provide inputs for AoR reevaluation modeling, evaluate predictions of plume move ment, 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 pub lic that GS projects are proceeding according to plan, provide sufficient information to the ow ner or operator and Director, or allow for appropriate actions to address any indi cation that USDWs ma y be endangered.

49EPA disagrees that plume and pressure front mon itoring are not justified for Class VI wells. The Agency recognizes that while there are similari ties between injection of wastes for disposal (Class I) and GS (Class VI), there are signifi cant 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 characteris tics of anticipated GS projects, EPA believes that plume and pressure front m onitoring at §146.90(g) are justifie d to provide early warning of any unforeseen fluid movement that might endanger USDWs.

The final rule (at §146.90(g)) requi res owners or operators to pe rform monitoring to track the extent of the CO2 plume and pressure front. The owner or operator must use direct methods to monitor for pressure change s in the injection zone.

§146.90(g)(2) requires owners or oper ators 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 Direct or determines based on site-spe cific geology that such methods are not appropriate. For example, geophysical met hods are difficult to execute in areas that are structurally and topographically co mplex 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 thei r permit application.

EPA disagrees that pressure fall-off tests are an appropriate substitute for monitoring pressure changes in the injection zone. Pressure fall-off te sts provide information only in the vicinity of the injection well(s) and measure pressure cond itions within the inje ction zone only. Direct monitoring of pressure changes in the injection zone can provid e advance warning of movement of CO2 or brine that might ultimately endanger a USDW.

EPA acknowledges the commenters' concern abou t the cost of monitoring. However, EPA believes that monitoring is essential for protecti on of USDWs at GS site s. Although a significant cost in absolute terms, monito ring 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 mon itoring to assist owne rs or operators and Directors in evaluating requi rements under §146.90, including pr oposed monitoring plans. The guidance describes available technologies a nd recommended approaches for implementing a testing and monitoring plan. The guid ance 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 fr ont tracking (seeking comment)

Comment: 1. Monitoring CO2 Movement and Reservoir Pressure

50The preamble to the proposed rule specifica lly states that the "[m]onitoring of subsurface geochemistry and the position of the CO2 plume and pressure front are necessary to verify predictions of plum e 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 inje ction, 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 wh ile there are similarities between injection of wastes for disposal (Class I) and GS (Class V I), 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 visc osity (i.e., high mobility), and th e very large injection volumes that are anticipated. There is also a degree of unc ertainty regarding the be havior of large volumes

of CO2 in the subsurface after injection. Given these characteristi cs of anticipated GS projects, EPA believes that plume and pressure front m onitoring at §146.90(g) are justified to provide early warning of any unforeseen fluid m ovement that might endanger USDWs.

The final rule (at §146.90(g)) requi res owners or operators to pe rform 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 met hods (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down- hole CO2 detection tool s) are also required unless the Director determines, based on site-s pecific geology, that such methods are not appropriate.

EPA believes that pressure monitoring in th e injection zone is n ecessary 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 m odeling, evaluate predictions of plume movement, and target additional geoche mical 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 subsurf ace are problematic in a variety of respects. They are expensive to install, create potential pathways for vertical fluid migration, and - in the deep subsur face where natural fluid movement may be very slow or effectively non-existent - they have little pot ential to provide more than an isolated "point measuremen ts." Monitor wells al so have built-in

51confounding factors that incl ude both the potential fo r well construction to impact fluid quality in the target sampli ng interval and the fact that sampling may itself cause fluid movement that might not otherwise occur. Because pressure fronts extend much further than inject ed 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 injec tion 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 cont ext, 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 us eful 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 we lls 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 be tween the injection zone and USDWs or other layers above the confining zone. Such constructi on technologies exist and have b een used in the oil and gas industry for years. EPA believes th at 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 require s 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 cons truction that will include recommendations for monitoring well construction. The guidance wi ll be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

While EPA chose not to impose similar monitori ng requirements on other classes of injection wells (except for Class I hazardous waste inje ction 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 monitori ng wells sited based on site-speci fic information will provide

direct information that is not otherwise obtai nable and, along with othe r monitoring data, will support a broader understanding of fl uid behavior at the site.

EPA adds that the iterative process of monitoring, mode ling, 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 de lineation model (or identif y needed changes), and refine testing and monitoring activities to ensu re that USDWs are protected from endangerment

52and that there would be adequate warning of potential problems at the site before any endangerment could occur.

EPA acknowledges the commenters' concern abou t the cost of monitoring. However, EPA believes that monitoring is essential for protecti on of USDWs at GS site s. Although a significant cost in absolute terms, monito ring costs are expected to be a small fraction of site operating costs, according to EPA's cost analysis for the GS rulemaking (which is av ailable in the docket).

EPA is developing guidance on testing and mon itoring to assist owne rs or operators and Directors in evaluating requi rements under §146.90, including pr oposed monitoring plans. The guidance describes available technologies a nd recommended approaches for implementing a testing and monitoring plan, including pre-ope rational geophysical l ogging and testing of injection wells, MITs, injecti on well testing during operation, groundwater quality monitoring, tracking the CO2 plume and pressu re front, and soil, gas, and su rface-air monitoring which may be required by the UIC Director for specific GS projects. Th e guidance can be found on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_se questration.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 mon itor wells, the proposed rule suggests that it may be possible to use remote geophysical techni ques for "plume tracking." 73 Fed. Reg. at 43515. Unfortunately, the technologies ava ilable would be very expensive to employ on the scale required. Seeking to ach ieve 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 fr ont. The owner or operator must use direct methods to monitor for pressure chan ges in the injection zone. Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down-hol e CO2 detection tools) are required unless the Director determines, based on site-specifi c geology, that such methods are not appropriate.

EPA believes that pressure monitoring in th e injection zone is n ecessary 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 m odeling, evaluate predictions of plume movement, and target additional geoche mical 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.

53EPA is affording Director's disc retion regarding the use of geophys ical techniques at some sites because the Agency recognizes that geophysical methods are not appropriate in all geologic settings. For example, geophysical methods are diffi cult 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 mon itoring to assist owne rs or operators and Directors in evaluating requi rements under §146.90, including pr oposed monitoring plans. The guidance describes available technologies a nd recommended approaches for implementing a testing and monitoring plan, including pre-ope rational geophysical l ogging and testing of injection wells, MITs, injecti on well testing during operation, groundwater quality monitoring, tracking the CO2 plume and pressure front, and soil, gas, and surface ai r monitoring which may be required by the UIC Director for specific GS projects. Th e guidance can be found on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_se questration.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 recomme nding sufficient requirements to ensure that this goal is achieved. As EPA seems to recognize, surface air or soil gas monitoring would impose substantial cost s and the results of such monitoring would be subject to a host of confounding f actors. 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 ga s monitoring are subject to sitespecific limitations and may not be suitable in all settings as a me thod 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 ensu re USDW protection, direct

correlation of CO2 at the surface with CO2 in th e subsurface might be difficult; however, when combined with information gathered through othe r monitoring techniques required of GS well owners and operators (e.g., monitoring wells, geophysical te chniques), air and soil gas monitoring may provide valuable data on the magnitude and location of a leak.

54The decision to use surface monitoring and the selection of monitoring methods will be sitespecific (e.g., may be influenced by geology, in jection depth, and opera tional 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 discreti on 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 UI C 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 fr om endangerment, surface air and soil gas monitoring will increase USDW protection, enable immediate no tification of the UIC Director in the case of potential USDW endangerme nt, and facilitate remedial action.

Letter ID: 0190 Comment ID: 24359 Letter Lines: 1370 to 1383

Comment Code: 5430 2.9.1 Comments on proposed financia l responsibility requirements (40 CFR 146.85)

Comment: H. Financial Assurance

We support EPA’s flexible approach on fina ncial assurance methods. It would be a mistake to impose any regulatory restricti ons that would preclude the use of particular types of financia l assurance or particular in struments, regardless of whether those are currently used for othe r classes of inject ion wells or in other EPA programs. Allowing for flexib ility recognizes that operators are likely to use combinations of approaches and instruments to meet these requirements and that these combinations ma y change significantly over time as operators, program Directors and the financ ial markets gain more experience with geologic sequestration projects. EPA’s is wise to avoid any artificial constraints on the development of poten tially acceptable means of achieving

financial assurance. We recommend that th is approach be retained in the final

rule.

Individual Response: EPA agrees that it is appropriate to al low 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 ma y 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 responsibil ity 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 prio r 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 eval uate appropriate financial met hods and states may set more

55specific financial responsibility requirements if they so choose. This guidance is available on EPA's website at http://wat er.epa.gov/type/groundwater/ui c/wells_sequestration.cfm.

Owners or operators may select different instru ments 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 responsibil ity 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 fo r 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 a pproach to financial responsibility.

Given that the practice of GS is fairly ne w 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 determ ine 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 re vision 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 in jecting large volumes of CO2 a nd to ensure that USDWs are protected from endangerment. The GS rule c ontains tailored requirements for the permitting, geologic site characterization, AoR and corre ctive action, well construction, operation, mechanical integrity testing, monitoring, well plu gging, post-injection site care, and site closure of GS wells that directly addre ss 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 in jection 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

56OCCURRING 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 HIGHE R 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 inj ection "as long as any production is occurring." EPA has aske d for comment on the merits of this approach "since owners or operators of so me 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 ab out 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" defi nition as to the applicable class of wells where CO2 inj ection 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 rema in 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 pr esented by the multi-stakeholder group, in which the Carbon Sequestrati on Council participated.

Individual Response: EPA did not make the suggested change . The Agency disagrees that wells injecting CO2 for the primary purpose of long-te rm storage should be regulated under Class II requirements. The Agency believes that the natu re 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 regul ations 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 re quire that any owner or operato r injecting CO2 for the primary purpose of long term storage obtain a Class VI pe rmit with some special consideration for the fact that they are transitioning from a well not or iginally designed to meet Class VI requirements. The Director has the authority to determine at wh at point a Class VI permit is required for those

57projects that are transitioning from the primar y purpose of EOR to long term storage of CO2. The final regulation provides a set of technical factors for the Direct or to evaluate in making this determination, at §144.19. EPA believes that this approach provides su fficient protection of

USDWs when there is an increased risk to USDWs as compared to traditi onal Class II operations while allowing for site-specific flexibility.

EPA is developing guidance on transitioning perm its 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 purpos e is oil and gas production, to Class VI, where the primary purpose is long-term storage of large volumes of CO2. The gu idance describes the recommended methods the Director may use to evaluate change s in risk to USDWs from projects, and how the Director may determine whether a project should be regulated within th e Class II or Class VI UIC program. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequest ration.cfm. For more information, please

see the discussion on transition of Class II well s 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 in jection 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 DI OXIDE 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 wide ly recognized that CO2 based EOR can provide a significant early opportunity fo r 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 receivi ng formation during CO2 EOR operations. Following abandonment of EOR operations, a ssuming 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 inj ected can be permanently stored.

We recommend that all GS into basalts, coal seams, and salt domes be conducted under Class V as experimental wells initia lly and then as commercial scale Class

58V 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 a llow 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 vi able formations from consideration. It has been shown that it is possible to operate CO2 injection wells in an EOR context without endangering US DWs that are located below the injection zone. An excellent example is the Salt Creek EOR pr oject in Wyoming, which has a USDW below the injection zone. Under the proposed rule, there are othe r measures that would provide real assurance of formati on integrity and require operators to demonstrate that their project will not endanger USDWs, making the lowermost USDW restriction unnecessary. Instead, operato rs should be able to show adequate containment to prevent endangerment of US DWs both above and below the injection zone used for geologic sequestration.

Individual Response: As described above regarding the su ggested edit at 144.6(b), EPA did not make the suggested change. The Agency disagr ees 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, a nd salt domes, EPA clarifies that the GS rule does not categorically preclude inje ction 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 th at wells are sited in suitable sy stems with geologic formations to receive and confine injected CO2, as require d at §146.83 of the GS rule. The Class VI siting, well construction and operation, monitoring and te sting, and post-injectio n site care and site closure requirements are designed to ensure th at injected CO2 remains within the target formation. If an owner or operator can demonstrate to the Director's satisf action 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, th e project may be permitted as a Class VI well.

EPA acknowledges that there may be unknown risks a ssociated with GS, pa rticularly 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 anti cipates 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 th e Class V experimental technology well classification to clarify perm itting for Class V wells. This addendum will address shifting of Class V experime ntal projects to Class VI proj ects and the future use of the

59Class V experimental technology we ll subclass for research and te sting of new GS technologies.

EPA acknowledges that there are limited circum stances where injectio n above the lowermost USDW can be performed in a manner that pr otects USDWs. The final GS rule at §146.95 establishes a process by which owne rs or operators can seek a waiv er of the Class VI injection depth requirements. The waiver approach requir es the submission of extensive, site-specific information (in conjunction with the permit appli cation submittal) to dem onstrate that injection

of CO2 into a formation that is above or be tween USDWs can be done in a manner that is protective of USDWs. The requirements are desi gned 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 vi able formations from consideration. It has been shown that it is possible to operate CO2 injection wells in an EOR context without endangering US DWs that are located below the injection zone. An excellent example is the Salt Creek EOR pr oject in Wyoming, which has a USDW below the injection zone. Under the proposed rule, there are othe r measures that would provide real assurance of formati on integrity and require operators to demonstrate that their project will not endanger USDWs, making the lowermost USDW restriction unnecessary. Instead, operato rs should be able to show adequate containment to prevent endangerment of US DWs 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 aminimum injection depth for GS projects and the Agency believes that a determination of sitesuitability for GS (i.e., that subsurface formati ons 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- a nd 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/ed its to rule language

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

Comment: Rule Provision: 144.15

60Proposed 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, operatio n or maintenance of any non

- experimental Class V geologic sequestration well is prohibited.

Basis for CCS Group Comments: This provisi on should be deleted if EPA does limit Class VI wells to injection below the lowe rmost 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 th e 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/ed its 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/ed its to rule language

Comment Code: 5700 2.12 Comments on the proposed durati on of Class VI permits (seeking comment)

Comment: Rule Provision: 144.36

Proposed CCS Group Recommendations: (a) Perm its 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 th e operating life of the facility.

61PERMITS FOR CLASS VI WELLS AND FO R OTHER WELLS USED FOR GEOLOGIC SEQUESTRATION

OF CO2 STREAMS SHALL BE EFFECT IVE FOR THE PERI OD THROUGH SITE

CLOSURE.

Basis for CCS Group Comments: Permits are necessary for geologic sequestration wells through the end of th e 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 sp ecifies that Class VI permits will be issued for the operating life of the facility and the post-injection site car e 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 discussi on 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 experiment al 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 na ture and would be to test new technologies, and that EPA does not consider it appropriate to permit CO2 injecti on wells that are testing the injectivity or appropriateness of an individual fo rmation (e.g., as a prelude to a co mmercial-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 th e Class V experimental technology well classification to clarify perm itting for Class V wells. This addendum will address shifting of Class V experi mental projects to full-scale GS projects and the future use of the Class V experimental technology well s ubclass for research a nd 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/ed its to rule language

62Comment 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 define d 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 disc retion to allow the scheduling of the initial MIT after some injection has occu rred, 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 mechani cal 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/ed its to rule language

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection 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: TH ESE SECTIONS MAY REQUIRE FURTHER

REVISIONS

TO PROVIDE CONFORMING LANGUAGE.

Basis for CCS Group Comments: The multi-st akeholder group has agreed that proposed language describing wells in cl assification (b)(4) establishes a "bright line" definition for wells that inject CO2 for EOR/EGR and GS and, consistent with EPA’s intent, should rema in 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 me t." But we have not yet attempted to define what specific requirements should apply to these wells. We are committed

63to working toward agreement on those re quirements (probably within a Class II context) and submitting the results of th at 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 experiment al 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 shoul d remain under the Class II Program. However, the Agency disagrees that wells injecting CO 2 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 s ites. EPA also recognizes that a by-product of

EOR activities is that a certain percentage of the CO2 is trappe d 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 c onditions will also be differe nt, 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 ru le 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, ba salts, 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 perm itted 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 si x years, to collect a nd review data on GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determ ine 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/ed its to rule language

Comment Code: 5900 2.14 Other administrative re quirements under 40 CFR 144

64Comment: 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. Pleas e see the remainder of EPA's responses to this comment letter for further de tails. 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/ed its to rule language

Comment Code: 5900 2.14 Other administrative re quirements 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. Pleas e see the remainder of EPA's responses to this comment letter for further de tails. 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/ed its to rule language

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection 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) Cl ass 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

65INSIGNIFICANT FUTURE

PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION AND (II)

OPERATING PRESSURES ARE NO HIGHE R 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 inj ection "as long as any production is occurring." EPA has aske d for comment on the merits of this approach "since owners or operators of so me 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 ab out 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" defi nition as to the applicable class of wells where CO2 inj ection 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 rema in 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 pr esented by the multi-stakeholder group, in which the Carbon Sequestrati on 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 Cla ss II requirements.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisi ons to the GS Rule. S ee the final rule and preamble for further discussion on EPA's final appr oach 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/ed its to rule language

Comment: Rule Provision: 144.80(e)

Proposed CCS Group Recommendations: Support the proposed language.

66Individual 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 SE QUESTRATION 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 wide ly recognized that CO2 based EOR can provide a significant early opportunity fo r 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 receivi ng formation during CO2 EOR operations. Following abandonment of EOR operations, a ssuming 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 inj ected can be permanently stored.

We recommend that all GS into basalts, coal seams, and salt domes be conducted under Class V as experimental wells initia lly 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 a llow 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 bl anket prohibition con cerning 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, unde r the proposed rule, there are other

67measures that would provide real assura nce of formation integrity and require operators to demonstrate that their proj ect will not endanger USDWs, making the lowermost USDW restriction unnecessary. In stead, operators should be able to show adequate containment to prevent e ndangerment of USDWs both above and below the injection zone used fo r geologic sequestration.

Individual Response: As described above regarding the su ggested edit at 144.6(b), EPA did not make the suggested change. The Agency disagr ees 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, a nd salt domes, EPA clarifies that the GS rule does not categorically preclude inje ction 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 th at wells are sited in suitable sy stems with geologic formations to receive and confine injected CO2, as require d at §146.83 of the GS rule. The Class VI siting, well construction and operation, monitoring and te sting, and post-injectio n site care and site closure requirements are designed to ensure th at injected CO2 remains within the target formation. If an owner or operator can demonstrate to the Director's satisf action 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, th e project may be permitted as a Class VI well.

EPA acknowledges that there may be unknown risks a ssociated with GS, pa rticularly 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 anti cipates 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 th e Class V experimental technology well classification to clarify perm itting for Class V wells. This addendum will address shifting of Class V experime ntal projects to Class VI proj ects and the future use of the Class V experimental technology we ll subclass for research and te sting of new GS technologies.

EPA acknowledges that there are limited circum stances where injectio n above the lowermost USDW can be performed in a manner that pr otects USDWs. The final GS rule at §146.95 establishes a process by which owne rs or operators can seek a waiv er of the Class VI injection depth requirements. The waiver approach requir es the submission of extensive, site-specific information (in conjunction with the permit appli cation submittal) to dem onstrate that injection

of CO2 into a formation that is above or be tween USDWs can be done in a manner that is protective of USDWs. The requirements are designe d 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.

68Letter ID: 0190 Comment ID: 24384 Letter Lines: 1633 to 1643

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection 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 wide ly recognized that CO2 based EOR can provide a significant early opportunity fo r 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 receivi ng formation during CO2 EOR operations. Following abandonment of EOR operations, a ssuming 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 inj ected 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 CO 2 for the primary purpose of long-term storage should be regulated under Class II requirements.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisi ons to the GS Rule. S ee the final rule and preamble for further discussion on EPA's final appr oach 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 initia lly 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 a llow 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 na ture and would be to test new technologies, and that EPA does not consider it appropriate to permit CO2 injecti on wells that are testing the injectivity or appropriateness of an individual fo rmation (e.g., as a prelude to a co mmercial-scale operation) as

69Class 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 th e Class V experimental technology well classification to clarify perm itting for Class V wells. This addendum will address shifting of Class V experi mental projects to full-scale GS projects and the future use of the Class V experimental technology well s ubclass for research a nd 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 bl anket prohibition con cerning 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, unde r the proposed rule, there are other measures that would provide real assura nce of formation integrity and require operators to demonstrate that their proj ect will not endanger USDWs, making the lowermost USDW restriction unnecessary. In stead, operators should be able to show adequate containment to prevent e ndangerment of USDWs both above and below the injection zone used fo r geologic sequestration.

Individual Response: As described above, EPA acknowledges that there are limited circumstances where injection above the lowerm ost 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 owne rs or operators can seek a waiv er of the Class VI injection depth requirements for injecti on into non-USDW formations a bove and/or between USDWs.

Letter ID: 0190 Comment ID: 24387 Letter Lines: 1668 to 1672

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5900 2.14 Other administrative re quirements 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.

70Individual Response: EPA acknowledges the comment. Pleas e see the remainder of EPA's responses to this comment letter for further de tails. 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/ed its to rule language

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection 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) Cl ass 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 HIGHE R 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 inj ection "as long as any production is occurring." EPA has aske d for comment on the merits of this approach "since owners or operators of so me 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 ab out 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" defi nition as to the applicable class of wells where CO2 inj ection 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 rema in in Class II and be subject to the

Individual Response: As described above, EPA did not make the suggested change. The

71Agency disagrees that wells in jecting CO2 for the primary purpose of long-term storage should be regulated under Clas s II requirements.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisi ons to the GS Rule. S ee the final rule and preamble for further discussion on EPA's final appr oach 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 c onditions will also be differe nt, 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/ed its to rule language

Comment Code: 5900 2.14 Other administrative re quirements 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. Pleas e see the remainder of EPA's responses to this comment letter for further de tails. 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 SE QUESTRATION EXCEPT THOSE WELLS

DESCRIBED IN SUBSECTION (B)(4) OF THIS SECTION OR OTHERWISE EXCLUDED FROM THIS

72CLASS.

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 wide ly recognized that CO2 based EOR can provide a significant early opportunity fo r 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 receivi ng formation during CO2 EOR operations. Following abandonment of EOR operations, a ssuming 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 inj ected can be permanently stored.

We recommend that all GS into basalts, coal seams, and salt domes be conducted under Class V as experimental wells initia lly 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 a llow 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 bl anket prohibition con cerning 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, unde r the proposed rule, there are other measures that would provide real assura nce of formation integrity and require operators to demonstrate that their proj ect will not endanger USDWs, making the lowermost USDW restriction unnecessary. In stead, operators should be able to show adequate containment to prevent e ndangerment of USDWs both above and below the injection zone used fo r geologic sequestration.

Individual Response: As described above regarding the su ggested edit at 144.6(b), EPA did not make the suggested change. The Agency disagr ees 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, a nd salt domes, EPA clarifies that the GS rule does not categorically preclude inje ction 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 th at wells are sited in suitable sy stems with geologic formations to receive and confine injected CO2, as require d at §146.83 of the GS rule. The Class VI siting,

73well construction and operation, monitoring and te sting, and post-injectio n site care and site closure requirements are designed to ensure th at injected CO2 remains within the target formation. If an owner or operator can demonstrate to the Director's satisf action 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, th e project may be permitted as a Class VI well.

EPA acknowledges that there may be unknown risks a ssociated with GS, pa rticularly 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 anti cipates 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 th e Class V experimental technology well classification to clarify perm itting for Class V wells. This addendum will address shifting of Class V experime ntal projects to Class VI proj ects and the future use of the Class V experimental technology we ll subclass for research and te sting of new GS technologies.

EPA acknowledges that there are limited circum stances where injectio n above the lowermost USDW can be performed in a manner that pr otects USDWs. The final GS rule at §146.95 establishes a process by which owne rs or operators can seek a waiv er of the Class VI injection depth requirements. The waiver approach requir es the submission of extensive, site-specific information (in conjunction with the permit appli cation submittal) to dem onstrate that injection

of CO2 into a formation that is above or be tween USDWs can be done in a manner that is protective of USDWs. The requirements are designe d 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 in jection 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 wide ly recognized that CO2 based EOR can provide a significant early opportunity fo r 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 receivi ng formation during CO2 EOR operations. Following abandonment of EOR operations, a ssuming 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 inj ected can be permanently stored.

74Individual Response: As described above regarding the suggested edit at 144.6, EPA did not make the suggested change. The Agency acknowl edge that some CO2 stays trapped in the formation, but disagrees that we lls injecting CO2 for the primar y purpose of long-term storage should be regulated under Class II requirements.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisi ons to the GS Rule. S ee the final rule and preamble for further discussion on EPA's final appr oach 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 initia lly 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 a llow 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 na ture and would be to test new technologies, and that EPA does not consider it appropriate to permit CO2 injecti on wells that are testing the injectivity or appropriateness of an individual fo rmation (e.g., as a prelude to a co mmercial-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 th e Class V experimental technology well classification to clarify perm itting for Class V wells. This addendum will address shifting of Class V experi mental projects to full-scale GS projects and the future use of the Class V experimental technology well s ubclass for research a nd 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

75Comment: Additionally, there should not be a bl anket prohibition con cerning 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, unde r the proposed rule, there are other measures that would provide real assura nce of formation integrity and require operators to demonstrate that their proj ect will not endanger USDWs, making the lowermost USDW restriction unnecessary. In stead, operators should be able to show adequate containment to prevent e ndangerment of USDWs both above and below the injection zone used fo r geologic sequestration.

Individual Response: As described above, EPA acknowledges that there are limited circumstances where injection above the lowerm ost 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 owne rs or operators can seek a waiv er of the Class VI injection depth requirements for injecti on into non-USDW formations a bove and/or between USDWs.

Letter ID: 0190 Comment ID: 24394 Letter Lines: 1758 to 1762

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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: TH ESE SECTIONS MAY REQUIRE FURTHER

REVISIONS

TO PROVIDE CONFORMING LANGUAGE.

Basis for CCS Group Comments: The multi-st akeholder group has agreed that proposed language describing wells in cl assification (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 rema in 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 me t." 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 re quirements (probably within a Class II context) and submitting the results of th at 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 experiment al 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 shoul d remain under the Class II Program. However, the Agency disagrees that wells injecting CO 2 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 s ites. EPA also recognizes that a by-product of

EOR activities is that a certain percentage of the CO2 is trappe d 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 c onditions will also be differe nt, 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 ru le 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, ba salts, 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 perm itted 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 si x years, to collect a nd review data on GS

77projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determ ine 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 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: Basis for CCS Group Comments: The multi-st akeholder group has agreed that proposed language describing wells in cl assification (b)(4) establishes a "bright line" definition for wells that inject CO2 for EOR/EGR and GS and, consistent with EPA’s intent, should rema in 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 me t." 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 re quirements (probably within a Class II context) and submitting the results of th at 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 sufficien tly different from Class II ER operations and warrants tailored requirements. For example, the vo lume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reser voir pressure conditions will also be different, with Class VI injection opera tions involving large volumes of CO2 and likely having higher pressures within their storage forma tions than Class II ER projects.

EPA agrees that injection of CO2 for the prim ary purpose of enhancing oil and gas recovery should remain under the Class II Program. EPA be lieves that there are significant differences between how projects are operated, as well as the risks posed by thes e 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 tailore d specifically to addr ess 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 perm its 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 gu idance describes the recommended methods the Director may use to evaluate change s in risk to USDWs from projects, and how the Director may determine whether a project should be regulated within th e Class II or Class VI UIC program. This guidance will be available on EPA’s website at

78http://water.epa.gov/type/groundwat er/uic/wells_sequest ration.cfm. For more information, please

see the discussion on transition of Class II well s 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 experiment al 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 na ture and would be to test new technologies, and that EPA does not consider it appropriate to permit CO2 injecti on wells that are testing the injectivity or appropriateness of an individual fo rmation (e.g., as a prelude to a co mmercial-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 th e Class V experimental technology well classification to clarify perm itting for Class V wells. This addendum will address shifting of Class V experi mental projects to full-scale GS projects and the future use of the Class V experimental technology well s ubclass for research a nd 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/ed its 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 fo r 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, BA SALTS, OR SALT CAVERNS.

Basis for CCS Group Comments: See 144.6 and the note immediately above about the requirement for conforming language.

79Deleted "gaseous, liquid or supercri tical" 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 in to basalts, coal seams, and salt domes. Based on its evaluation of all public comments and input on the propos ed rule and NODA and Request for Comment, EPA has made many re visions 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/ed its 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) Th is 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 seques tration 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 T HAT 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 di scretion to exempt other Class VI requirements.

Individual Response: EPA disagrees that other requirement s (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., increa sed reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO 2 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,

80reporting, plugging, and post-in jection site care and site closur e 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 impacte d by the injection activity. The area of review is based on computational modeling that accounts for the physical and chemical prope rties 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 injecti on activity. Acceptable delineation models will provide predictions of CO 2 fate and transport, as well as changes in formation pressure, in three dime nsions, as a function of time that can be used to delineate the subsurface storage site and the AoR. Although EP A 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 regi on surrounding the geologic sequestration project where USDWs may be endangered by the injection activity. The ar ea 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 base d on available site characterization, monitoring, and operational data. EPA believes that this defi nition is sufficiently broad and describes both the intent of the computational modeling and the relationship of th e AoR to areas that are subject

to the risks associat ed 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 i ssues (seeking comment)

81Comment: Rule Provision: 146.81(d) [Definitio n - Carbon dioxide stream]

Proposed CCS Group Recommendations: Carbon dioxide stream means carbon dioxide,

IN ANY PHYSICAL STATE OR FORM, AND ANY AS SOCIATED substances derived from

the that has been captured from an emi ssion 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 substa nces added to enable or improve the injection process. This subpa rt 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 si nce that is beyond the scope of this regulation. Original text would have pr ecluded injection of CO2 from some

sources.

Individual Response: The final GS rule retains the defini tion of a CO2 stream as proposed. The GS regulation applies to injecti on 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 th e 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 char acteristics of the CO2 stream because the

concentrations of minor and tra ce elements in CO2 streams for GS projects are likely to vary by facility, coal composition, plant operating cond itions, 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: Confini ng zone means a geological formation, group of formations, or part of a forma tion 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 warra nt a change. In ad dition, the word "above" should be changed to "from" to acco mmodate situations where USDWs may be

82beneath 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 require ment 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: Geolog ic 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 de finition 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 sequestrati on at §146.81(d) to read as follows: “[T]he longterm containment of a gaseous, liquid, or s upercritical carbon dioxide stream in subsurface geologic formations. This term does not appl y to carbon dioxide captu re or transport.”

The final definition of carbon di oxide stream also remains uncha nged. Carbon dioxide stream is defined at §146.81(d) as: “[C]ar bon dioxide that has been captu red from an emission source (e.g., a power plant), plus incidental associated substances derived from the source materials and

83the capture process, and any subs tances added to the stream to enable or improve the injection process. This subpart does not apply to any carb on 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 Cla ss 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: Geolog ic sequestration project means an injection well or wells used to empl ace a carbon dioxide stream beneath the lowermost formation containing a USDW INTO AN INJECTION ZO NE EXCLUSIVELY FOR THE PURPOSE OF GEOLOGIC SEQUESTRATION. It includes the subsurface threedimensional extent of the carbon dioxide pl ume, associated pressure front, and displaced brine, as well as the surf ace area above that delineated region.

Basis for CCS Group Comments: There s hould not be a bla nket prohibition concerning injection above USDW’s or at sp ecific depths. This requirement is not necessary for the protection of USDWs and would remove a vast number of viable

formations from consideration. Industr y 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 exam ple is the Salt Cree k EOR project in Wyoming, which has a USDW below the inject ion zone. Moreover, under the proposed rule, there are other measures that woul d provide real assura nce of formation integrity and require operators to dem onstrate that their project will not endanger USDWs, making the lowermos t USDW restriction unnecessary.

Individual Response: EPA has revised the definition of a geologic sequestra tion project to account for the new requirements to include “w ells 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]

84Proposed CCS Group Recommendations: Injection zone means a geologic formation, group of formations, or part of a fo rmation that is of sufficient areal extent, thickness, porosi ty, 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 defi nition in the CFR is sufficient and does not need to be changed. Furthermore, adding the sufficiency requirement is

not a definitional issue and shoul d 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 Cla ss 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 "appr opriate" 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 discussi on on EPA's final approach. EPA adds that all post-injection site care must be pe rformed pursuant to the post-injec tion 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

85Comment 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 injecti on of the carbon dioxide STREAM into the subsurface, For the purposes of this s ubpart, 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 fo rmation 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 Cla ss 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 furthe r 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

86Comment 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: transmi ssible 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 "bet ween formations" is inaccurate since there can be multiple formations within an injection zone. The critical factor for transmissivity is movement of in jected 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 a ddress 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/ed its to rule language

Comment: Rule Provision: 146.82 [I ntroductory 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/ed its 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.

87Letter ID: 0190 Comment ID: 24413 Letter Lines: 1969 to 1988

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3130 2.1.3 Comments that operators s hould 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) fo r which a permit is sought and the applicable area of review. Within the ar ea of review, the map must show the number, or name and location of all KNO WN 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 inte nded 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 re move any implication that an applicant

has to conduct studies to de termine 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., previ ously available) data. Site-specific conditions may affect the suitability of a proposed site. Ther efore the owner or operator must provide to the Director the necessary preliminary in formation to support a permit decision.

EPA did not delete “faults” fr om §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 regard ing characterizing the region al geology and hydrogeology of a proposed GS site as well as performing th e necessary geochemical, geomechanical, and geophysical analyses of the injection and conf ining zone. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestrati on.cfm. Please see the final rule and the discussion of geologic site characterization in the preamble for additional

information.

88EPA 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, a nd data quality. For instance, in m eeting the requirement to tabulate information on wells in the AoR, the Director ha s 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 fract ures (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/ed its 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 we ll and the formation as required by paragraphs (l), (r), a nd (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 a lign 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 avai lable 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 in formation to be submitted before operation of the well is authorized (at §146.82(c)).

EPA believes that this revisi on 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 inje ction well classes, which could help avoid confusion about how to meet the permitting requirem ents 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 modifi cations and additions th at address the unique challenges and types of data collected for GS wells.

The requirement to provide the final area of review based on m odeling and data obtained during

89logging and testing is in the fina l GS rule at §146.82(c)(1). Plea se 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/ed its to rule language

Comment Code: 3130 2.1.3 Comments that operators s hould 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 INJECTI ON AND CONFINING ZONE(S), A

STRUCTURAL CONTOUR MAP HUNG ON TH E TOP OF THE PROPOSED INJECTION ZONE, AND AT

LEAST TWO GEOLOGIC cross sections of th e area of review SHOWING THE GEOLOGIC

FORMATIONS FROM THE SURFACE TO TOTAL DEPTH.

(2) Location, orientation, and propertie s of known or suspec ted SUBSURFACE

faults and fractures that may transect the confin ing zone(s) in the area of review and a determination that they would not interfere with containment;

Basis for CCS Group Comments: If the in formation is not known, it cannot be reported.

"Reservoir" and changes to (1) a nd (2) are technical corrections.

Fractures generally can't be identified until a well is drilled and evaluated. Even then, only fractures in the immedi ate vicinity of the well bore can be

identified.

Individual Response: EPA acknowledges that some smaller fractures may not be detectable during the site characterization pr ocess, and clarifies that §146.82( a)(3)(ii) require s the owner or operator to submit data on known or suspected fau lts and fractures (i.e., no t all fractures). Other requirements for GS injection wells and sites can mitigate the potential impacts of unidentified fractures. These include limitations on injec tion pressures to avoid propagation of existing fractures in the confining zone (§146.88(a)), co llection 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

90should be limited to known (i.e., previously availa ble) data. Site-specifi c conditions may affect the suitability of a proposed site. Therefore the owner or operator must pr ovide 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/ed its to rule language

Comment Code: 3130 2.1.3 Comments that operators s hould 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) Info rmation 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 loca l and regional geology, and detailed review of any known or potential seismically activ e 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 w ith 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/ed its to rule language

Comment Code: 3130 2.1.3 Comments that operators s hould 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) Da ta SUFFICIENT TO DEMONSTRATE THE

EFFECTIVENESS OF THE INJECTION AND CONFINING ZONE(S), INCLUDING DATA

ON THE

91DEPTH, AREAL EXTENT, THICKNESS, MINERALOGY, POROSITY, VERTICAL

PERMEABILITY

RESERVOIR PRESSURE AND OF THE INJE CTION AND CONFINING ZONE(S) WITHIN

THE AREA OF REVIEW; INCLUDING GEOLOGIC CHAN GES BASED ON FIELD DATA WHICH MAY

INCLUDE GEOLOGIC CORES, OUTCROP DATA, SEISMI C SURVEYS, WELL LOGS, CAPILLARY

PRESSURE

TESTS AND NAMES and lit hologic descriptions;

Basis for CCS Group Comments: Capillary pres sure 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. Reword ing keeps the useful ness of capillary pressure in the provision without making it a mandatory use.

Individual Response: EPA acknowledges that laboratory met hods are standard for determining capillary pressures regardless of formation perm eability and that in si tu measurements would require drilling of a well. However, EPA also antici pates 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 cap illary 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 fina l 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 pr essures would be required following drilling of the well, at §146.82(c)(4).

EPA believes that information on capillary entry pr essure is necessary and appropriate. Capillary entry pressure measurements on core sample s 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/ed its to rule language

Comment Code: 3130 2.1.3 Comments that operators s hould 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

92fractures, stress, ductility, rock streng th, 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 charact erization requirements at §146.82, including geomechanical information and geologic and topogr aphic maps and cross sections, are essential to proper siting of a GS well and are the foundation for a detailed understa nding 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 proc ess. 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 fina l 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 pr essures 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/ed its 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 th e 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, dept h, 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)

93Proposed CCS Group Recommendations: (f) Ma ps and stratigraphic cross sections indicating the general vertical and lateral limits of all USDWs, water wells and springs within the area of review, thei r positions relative to the injection zone(s) and the direction of wat er movement, where known; POTENTIOMETRIC (WATER LEVEL) SURFACE MAP(S) OF EXISTING AQUIFERS BEING UTILIZED AS

PRIVATE OR

PUBLIC WATER SUPPLIES AND THE DI RECTION OF GROUNDWATER FLOW IN THESE AQUIFERS

WITHIN THE AREA OF REVIEW. AT LEA ST TWO GEOLOGIC CROSS SECTIONS

SHOWING THE

THICKNESS AND GENERAL VERTICAL A ND LATERAL LIMITS OF ALL USDWS

WITHIN THE AREA

OF REVIEW.

Basis for CCS Group Comments: This revi sion 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 a ll 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 lik ely 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 sear ch 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 unde rstanding of the hydrogeologic c onditions of all USDWs in the AoR is necessary, and disagrees with the su ggested edits because the GS rule, as written, affords flexibility to owners or operators and Di rectors to tailor the site characterization process to the unique features of the site. EPA enc ourages owners or opera tors and Directors to collaborate and consult during site characterization to discuss info rmation needs and ensure that all appropriate data to assess the suitability of the site are collected. The Director also has the

94authority to request additional hydrogeo logic 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 a ll USDWs in the AoR, is appropriate and protective of USDWs. EPA believe s that this data will support monitoring plan development, inform injectate fate and transport model de velopment (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 baseli ne 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 ar e 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 s ubsurface 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/ed its 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 ope rating data: (1) Average and maximum daily INJECTION rate and volume of the carbon dioxide

stream; (2) Average and maximum SURF ACE 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.

95Basis for CCS Group Comments: Agree with EPA’s rationale.

Rule Provision: 146.82(k)

Proposed CCS Group Recommendations: (k) Pr oposed 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 con cerns 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 th at wells not needi ng corrective action

will not have a corrective action status.

Individual Response: EPA acknowledges the commenter’s s upport for portions of the subject requirements. EPA disagrees that the suggested t echnical clarifications are necessary. EPA adds that it is developing guidance for owners or ope rators on the geologic si te characterization and AoR and corrective action processe s. These guidances will provide recommendations and clarify the intent of all required elem ents of a permit application. The guidances can be found on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_se questration.cfm.

Letter ID: 0190 Comment ID: 24421 Letter Lines: 2151 to 2155

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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.

96Letter ID: 0190 Comment ID: 24422 Letter Lines: 2157 to 2169

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 c onfining 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 keep s 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 re quirement at §146.83(a)(2) that the confining zone be free of transmissive faults or fractures is appropriate fo r Class VI wells and is necessary to ensure containment of the injectate and that requiring the co nfining zone to be free of transmissive faults maximizes protection of USDWs from endangerment. EPA believes that the text regarding propagation of faults and fractu res is important to avoi d the potential for fluid

movement and to ensure that injection is at appropriate pr essures. Class I hazardous waste injection well operators must also meet a similar re quirement 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 abse nce of or identify and characterize the presence

of faults or fractures. EPA adds that the Direct or 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/ed its 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 di scretion, owners or operators of Class VI wells must identify and characterize additional zones that will impede vertical fluid movement, are free o f faults and fractures that

97may interfere with containment, allow for pressure dissipation, and provide additional opportunities for monito ring, mitigation and remediation.

Basis for CCS Group Comments: This para graph creates a presumption that additional confining zones WILL be require d. It is also redundant given the previous sections. Providing for a confin ing zone that meets the requirements should be sufficient. Any further iden tification of confin ing zones would potentially eliminate zones useful for future geologic sequestration.

Individual Response: EPA clarifies that secondary confini ng zones are not required for all GS sites. Rather, secondary confini ng zones are required when the Di rector 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 pr imary (i.e., lowermost) confining zone can improve USDW protection. These layers could fu rther impede vertical fluid movement and allow for pressure dissipation, and also provide additional sites for monitoring, mitigation, and remediation. The Agency's decision is suppor ted 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/ed its to rule language

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling CO2 movement

Comment: Rule Provision: 146.84(a)

Proposed CCS Group Recommendations: (a) The area of review is the region surrounding the geologic sequest ration 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 prope rties of all phases of the injected

carbon dioxide stream. THE SUBSURFACE THREE-DI MENSIONAL 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 surf ace area and all subsurface

98formations below it that may potentially be impacted by injecti on activity. Acceptable delineation models will provide predictions of CO 2 fate and transport, as well as changes in formation pressure, in three dimensions, as a f unction of time that can be used to delineate the subsurface storage site and the AoR. Although EP A 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 regi on surrounding the geologic sequestration project where USDWs may be endangered by the injection activity. The ar ea 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 base d on available site characterization, monitoring, and operational data. EPA believes that this defi nition is sufficiently broad and describes both the intent of the computational modeling and the relationship of th e AoR to areas that are subject

to the risks associat ed with injection.

Letter ID: 0190 Comment ID: 24425 Letter Lines: 2198 to 2209

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 ow ner 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 sequest ration project, periodically reevaluate the delineation, and perform corrective action th at 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, f or approval by the Director the owner or operator must submit an area of review a nd corrective action plan that includes the following information:

Basis for CCS Group Comments: Clarification.

Individual Response: EPA disagrees with the suggested cha nge, and is retaining the approach of setting a minimum fixed frequency for reeval uating the AoR but has, based on commenters' input, changed the frequency from ten years to at least every five ye ars, as specified in §146.84(e). EPA agrees with commenters that site-specific informati on is an important factor in determining an appropriate AoR reevaluation freq uency, and adds that th e owner or operator's AoR and corrective action plan must describe th e minimum fixed frequency for reevaluating the AoR and the site-specific condi tions on which this frequency is based. EPA adds that the

Director will evaluate the proposed plan in connection wi th a review of a vast amount of geologic and proposed operating da ta in determining whether to approve the plan. EPA is developing guidance describing reco mmended approaches to prepar ing all of the required GS project plans, which will addres s 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.

99Letter ID: 0190 Comment ID: 24426 Letter Lines: 2211 to 2221

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 operati onal conditions that would warrant a

reevaluation of the area of review prior to the next scheduled reevaluation as determined by the minimu m fixed frequency established in paragraph (b)(2)(i) of

this section.

Basis for CCS Group Comments: These provisi ons in (i) and (ii) are rendered unnecessary by the revisions to section 146.84(b).

Individual Response: EPA believes that periodic AoR reevalua tion at a set frequency of at least every five years is necessary to ensure protec tion of USDWs from endang erment and address the uncertainties inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure that a deliberate effort is made to verify, base d 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 appropria tely model plume and pressure front movement,

establish conditions for corrective action, and ensure protec tion of USDWs from endangerment.

EPA clarifies that if site m onitoring data agrees with the existing AoR delin eation, a model recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration

that the current AoR delineation is ad equate 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/ed its 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

100Basis for CCS Group Comments: Agree with EPA’s rationale.

Individual Response: EPA acknowledges the comment and the fi nal rule retains this provision.

Letter ID: 0190 Comment ID: 24428 Letter Lines: 2231 to 2242

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 pa ragraph (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 ar ea 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 requiremen t as proposed. The purpose of the corrective action requirement at §146.84(d) is to ensure that a ll wells in the AoR that have the potential to cause the movement of CO2 or other fluids in to 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 pr oposed AoR and corrective action plan. In the AoR and corrective action plan, the owner or operato r must describe how site access will be guaranteed for future corrective actio n 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/ed its to rule language

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling CO2 movement

Comment: Rule Provision: 146.84(c)(1)

Proposed CCS Group Recommendations: (1) Pr edict, using computational modeling, the projected lateral and vertical migr ation of the carbon dioxide plume and

formation fluids in the subsurface from th e commencement of in jection activities until INJECTION INDUCED plume movement ceas es, 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:

101Basis for CCS Group Comments: Clarification

Individual Response: Based on an evaluation of all comment s 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 th e movement of injected fluids or formation fluids into a USDW are no longer present, or until the end of a fixe d 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/ed its to rule language

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling 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 in jection zone, confining zone and any additional zones ; and anticipated operating data, including injection pressures, rates and total volumes ove r the proposed life of the geological sequestration projectTHE DURATION OF INJECTION;

(ii) Take into account any RELEVANT geologic heterogeneities, AND data quality, and their possible imp act on model predictions; and

Basis for CCS Group Comments: Allows the use of all availabl e data, not just data collected specifically for this permit.

Individual Response: EPA agrees that detailed geologic da ta is invaluable to modeling an accurate AoR. EPA clarifies that owners or opera tors may use existing data as well as data collected during site characterizat ion 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 “o ther discontinuities” in additi on to geologic heterogeneities when predicting the AoR.

EPA disagrees that only the injection and conf ining zones should be included in AoR modeling of GS sites. EPA believes that the modeling shou ld also take into acc ount 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 ultimat ely protect a USDW from endangerment.

102Letter ID: 0190 Comment ID: 24431 Letter Lines: 2270 to 2274

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling 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/ed its to rule language

Comment Code: 3420 2.2.2.1 Scope of the inventory pr ocess (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 penetr ations 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, r ecord of plugging and/or completion, and any

additional information the Di rector may require; and

Basis for CCS Group Comments: Changed fo r consistency with earlier language.

Individual Response: EPA is retaining the requirement as proposed. EPA agrees with commenters that, for most GS sites, relying on da tabase and other public records searches (i.e., of "known" artificial penetrati ons) will be sufficient to meet the requirements at §146.84(c)(2). However, the Agency recognizes that there ma y 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 US DW 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 Direct or the discretion to require any additional information needed (including information that is not publically available) to ensure that all

103necessary corrective ac tion is performed.

Letter ID: 0190 Comment ID: 24433 Letter Lines: 2288 to 2295

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 "i n the area of review" as redundant.

Individual Response: EPA clarifies that the term "asso ciated 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 pre ssure front. EPA believes this terminology would incorporate any fluids in the subsurface that could potentially move through artificial penetrations and affect USDWs. EPA has revise d the language at §146.84(c)(3) to read,

"... carbon dioxide or other fluids that may endanger USDWs..." EP A disagrees that deleting the term area of review is necessary and has reta ined 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/ed its 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 revi ew IDENTIFIED IN 146.84(C)(2) that are dete rmined to need corrective action". using methods necessary to prevent the m ovement of fluid into or between USDWs including use of corrosion resist ant 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 re quire the use of materials that are

104"compatible with the carbon dioxide stream." EPA believes this language change addresses

commenters' concerns and is also consiste nt 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/ed its 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 ope rator must notify the Director and cease operations as required by § 146.94.

Basis for CCS Group Comments: This is no t needed since §146.94 already specifies the notification and cessation of inject ion. 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 fina l rule now contains a provision in §146.91(c) that requires the owner or opera tor 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/ed its 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 a pproved area of review and corrective action plan, or When monitoring and operational conditions warrant, owners or

operators must:

Basis for CCS Group Comments: Rather th an 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 fact ors should be considered in the reevaluation schedule, and notes that the AoR and corrective acti on plan must specify the sitespecific monitoring and operationa l conditions that warrant r eevaluation, as specified in §146.84(b)(2)(ii). In addition, the Director has discretion to require more frequent AoR

105reevaluation if he or she has r eason to believe, based on site-speci fic information, that a five-year

reevaluation schedule is not su fficiently protective of USDWs. However, EPA believes that setting a minimum reevaluation frequency is appr opriate. 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 th at this revised frequenc y addresses commenters'

concerns about the inherent unc ertainties in modeling CO2 move ment, the emerging nature of GS technology, risk-based targeti ng of monitoring activ ities, 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/ed its 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) Su bmit 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 cha nge 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/ed its to rule language

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling CO2 movement

Comment: Rule Provision: 146.84(g)

Proposed CCS Group Recommendations: (g) The em ergency and remedial response plan (as required by § 146.94) and a demonstra tion 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 wh ether or not correc tive action in the area of review is phased.

Basis for CCS Group Comments: Need to a dd phrase to account for the periodic reevaluations and possible revisi ons that will be occurring.

Individual Response: EPA agrees with the commenter and has modified the final rule at

106§146.84(f) to require the emergency and remedial response plan and the demonstration of financial responsibility to take into a ccount 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/ed its to rule language

Comment Code: 5430 2.9.1 Comments on proposed financia l 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 a nd resources for corrective action (that meets the requirements of § 146.84), inje ction well plugging (that meets the requirements of § 146.92), post-injection site care and site closure (that meets the requirements of § 146.93), and emergenc y and remedial response (that meets the requirements of § 146.94) in a manne r 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 AP PROPRIATE; and

Basis for CCS Group Comments: Maintena nce of the well plugging financial obligation until site closure is not necessary. The Director should have the authority to release the obliga tion once the well is plugged.

Individual Response: EPA will allow owners or operators to use separate financial responsibility instruments for different GS activ ities. However, owners or operators must demonstrate adequate financial re sponsibility for all re quired activities, in cluding 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 inflatio n, increase or decrease th e value of the financial instrument to match the cost estimate, and pr ovide any updated information related to their financial responsibility instrument(s), or at a ny other time deemed appropriate by the Director. These annual reviews provide a mechanism for revi sing cost estimates up or down to account for changes in the project, includi ng 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 fo r 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 fi nal approach to financial responsibility.

EPA is developing guidance on fina ncial responsibility for GS we lls. The guidance will include a

discussion on how best to estimate costs to assist Class VI well owners or operators, third party

107insurers or providers of financial instruments, and permitting authorities in developing estimates

of the costs associated with va rious 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/ed its to rule language

Comment Code: 5430 2.9.1 Comments on proposed financia l 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 adjustme nts to the cost estimate to account for any amendment s 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 cl osure 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 reeval uated after amendments to the area of review and corrective action plan, prior to well pl ugging or site closure, after amendments to the emergency and remedial response plan, or at a ny 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 m echanism for revising cost estimates up or down to account for changes in the project, includ ing the execution of en vironmental 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 th e 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/ed its to rule language

Comment Code: 5430 2.9.1 Comments on proposed financia l 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 financia l conditions such as bankruptcy , that may affect the ability to carry out injection well plugging and pos t-injection site care

108and 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 ma de many revisions to the GS rule. Please

see the final rule and the disc ussion of financial responsibilit y 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/ed its 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 re quired by §146.92) and po st-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 th at the GS rule, at §146.85(e), requires the owner or operator to provide annua l updates to the cost es timate 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/ed its 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) Prev ent the movement of fluid into or between USDWs or into any unauthorized zones; CONTAINING ANY CONTAMINANT

INTO USDWS, IF THE PRESENCE OF THAT C ONTAMINANT MAY CAUSE A VIOLATION OF

ANY PRIMARY

DRINKING WATER REGULATION UNDER 40 CFR PART 142 OR MAY OTHERWISE

109ADVERSELY AFFECT THE HEALTH OF PERSONS;

Basis for CCS Group Comments: The proposed changes follow the non-endangerment

standard that is the ba sis 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 move ment between formations is paramount and believes that the language as proposed meets the non-endangerment st andard. Appropriately designed and constructed wells ar e necessary to prevent endange rment 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-operationa l testing of Class VI wells at §§146.86 and

146.87.

Based on its evaluation of all public comment s 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/ed its to rule language

Comment Code: 3860 2.3.3 Well component degradation

Comment: Rule Provision: 146.86(b)(1)

Proposed CCS Group Recommendations: (1) Ca sing and cement or other materials

used in the construction of each Class VI well must have sufficient structural strength and be designed for the operati ng life of the geolog ic 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 PRACTICE S 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 or der 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 sequestra tion 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, ra ther than the life of the sequestration project. GS projects are anticipated to ha ve 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

110the GS project, but they must be constructe d 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-injec tion site care period and beyond. While th e risk profile of a GS site will decrease following cessation of in jection, 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 fo r 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/ed its 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 corro siveness 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/ed its 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) Do wn-hole temperatures AND PRESSURES;

Basis for CCS Group Comments: Technical clarification

Individual Response: EPA clarifies that information on do wn-hole pressures is required at §146.86(b)(1)(ii).

Letter ID: 0190 Comment ID: 24447 Letter Lines: 2443 to 2448

111Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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: (vii i) Type or grade of cement AND ADDITIVES; and

Basis for CCS Group Commen ts: 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/ed its 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 IN JECTION 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 combin ation of cement on the surface casing and long-string casing achieves c ontinuous cement through the base of the lowermost USDW above the injection zone. In some pa rts of the US, USDWs are very deep and this standard may preclude geologic sequest ration at otherwise appropriate sites

in these areas.

Individual Response: EPA believes that the regulations allo w 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 cemente d 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 me et the requirement, such as the use of staged cementing.

112The Director will evaluate the appropriaten ess of the owner or operator's proposed well construction procedures based on s ite-specific information about th e injection project, including injection pressures, injection and confining zone lithology, and information about the carbon dioxide stream as provided in §146.86(b)(1). Se e 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/we lls_sequestration.cfm.

As described above, EPA recognize s concerns regarding construc tion of Class VI wells where the lowermost USDW is very deep. To furthe r address comments on deep injection wells, the final GS rule at §146.95 includes requirements for ow ners 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/ed its 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 z one and must be cemented ISOLATED by circulating cement to the surface in one or more stages. PLACING CEMENT AND/OR OTHER

ISOLATION TECHNOLOGIES AS NECESS ARY 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 m onitor pressures in this annulus and would limit flexibility of remedial opti ons. As revised, the proposal would allow for application and de velopment of alternative t echnologies. 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 approp riate and offer appropriate flexibility: §146.86(b)(3) requires that the long- string casing extend to the inje ction zone and be cemented by circulating cement to the surface in one or mo re stages. It does not, however, specify how cementing would be accomplished, and gives flexib ility 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.

113EPA stresses that protection of USDWs is the primary mission and mandate of the UIC program and the purpose of all requirements for inject ion wells. Any injection activity must be demonstrated to not endanger USDWs, regardle ss 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 re quirements 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 owne rs or operators of Class I hazar dous and Class I municipal waste disposal wells. Some of these wells, whic h 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 Cl ass VI well construction requirements in the preamble to the final GS rule for additiona l 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/gr oundwater/uic/wells_se questration.cfm.

Letter ID: 0190 Comment ID: 24450 Letter Lines: 2484 to 2492

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 requireme nt 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/ed its to rule language

114Comment 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 carbo n dioxide stream and formation fluids and of sufficient quality and quan tity to maintain integrity over the design OPERATING life of the geologic sequestration project WELL. The integrity and location of the cement sha ll be verified using technology capable of evaluating cement quality radially and identifying th e 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 exis ting cementing materials and procedures. Standard API cements have been used in numerous CO2 EOR operations with no adverse consequences. Refer to the citati ons 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 reco very, 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 flexibil ity: it does not specify materials to be used; rather, it provides owners or operators with the fl exibility 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 mu st 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/ed its 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 Recommendati ons: (ii) Characteristics COMPOSITION of the carbon dioxide stream. (chemical content, cor rosiveness, temperature, and density);

115Basis 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) M AXIMUM PROPOSED Inje ction temperature and pressure; (iv) MAXIMUM PROPOSED Annular pressure; (v) MAXIMUM PROPOSED Injection rate (int ermittent 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 de nsity. The suggested revision to refer to CO2 "composition" would be less precise. EPA clarifie s that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and describe d. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provid e 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 th e maximum proposed injection pressure and maximum proposed annular pressure, respectively. EPA has revised §146.86(c)(3)(v) to read "proposed in jection rate (intermittent or continuous), and volume and/or

mass of the carbon dioxide stream." EPA believes th at reference to the co ntinuous 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/ed its 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) Du ring the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys and tests to determine or veri fy the depth, thickness, porosity,

116permeability, and lithology of, and the salin ity of any formation fluids in, all relevant geologic formations to assure EVALUATE conformance with the injection well construction requireme nts under §146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Dire ctor a descriptive re port prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, su ch logs and tests must include: THE DIRECTOR MAY REQUIRE SUCH LOGS AND TESTS AS MAY BE N EEDED AFTER TAKING INTO

ACCOUNT THE

AVAILABILITY OF SIMILAR DATA IN TH E 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 th e geologic information will not assure conformance with well construction requireme nts, just measure or evaluate it.

In well defined areas, these evaluatio ns 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 dril led, 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 in stalled for a project.

Individual Response: EPA disagrees that the requirements for logs, surveys, and tests are unnecessary. All logs, surveys, a nd 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 inform ation is needed to demonstrate that the well can be operated and tested in a manner that pr otects 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 possi ble with a single test.

EPA notes that the Director ha s the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information, and the Dire ctor 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 qu estion and core retrieval is not possible, as specified at §146.87(b) . EPA believes that logs and te sts must be performed on each well drilled regardless of existing information a bout the area to account for the complexity of CO2 injection well construction and the buoyanc y of CO2. Existing lithologic and geologic information may lack the details needed for site -specific well design a nd the geology needed to support protection of USDWs from endangerment.

117Letter ID: 0190 Comment ID: 24454 Letter Lines: 2560 to 2564

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 ag rees that logging and testing requirements are appropriate and ne cessary. 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/ed its 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) Resi stivity, 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 re quirements based on Di rector 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, survey s, and tests listed at §146.87(a) are necessary to verify information about the in jection 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/ed its 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

118density log, and a temperature log evaluation log(s) afte r the casing is set

and cemented.

Basis for CCS Group Comments: Unusual to ru n 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 flexibil ity 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 af ter 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/ed its 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 fina l 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/ed its 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) Re sistivity, 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 acc eptable 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

119Class VI wells. All logs, surveys, and test s listed at §146.87(a) are necessary to verify information about the injection and confining zone s and ensure that the well is being drilled and cased as approved and has mechanical integrity.

EPA notes that owners or operators will descri be in their permit applications how they will construct and test the well, and will also subm it site-specific information about the subsurface geology. The Director will evaluate the proposed logging activities al ong with site-specific geologic information to identify geologic data of interest.

EPA adds that, should alternative methods be show n to provide equivalent or better information or if site-specific conditions and risk factors dictate that other l ogs are necessary, the Director has the discretion at §146.87(a)(5 ) to require further logs and te sts if necessary and to approve alternative methods that provide eq uivalent or better information.

Letter ID: 0190 Comment ID: 24459 Letter Lines: 2612 to 2619

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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) afte r the casing is set

and cemented.

Basis for CCS Group Comments: The proposed ch ange provides more flexibility to select the appropriate log to demonstrate adequate cement bond.

Individual Response: EPA clarifies at 146.87(a)(3)(ii) that ow ners or operators must perform a cement bond (i.e., cement evaluation) log af ter 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/ed its 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 w ith 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

120Basis for CCS Group Comments: Technical and grammatical correcti ons in (4), (4) (ii) and (4)(iii). In (iv), "if require d 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 surv eys in evaluating mechanical inte grity 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 us ed 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 th e Director.”

Letter ID: 0190 Comment ID: 24461 Letter Lines: 2634 to 2641

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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) A ny alternative methods that provide equivalent or better informati on and that are required of an d/or approved of by the Director.

Basis for CCS Group Comments: We interpre t 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 request ed. 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 demons trate that such cores are representative of conditions at the well in questi on and core retrieval is not possi ble, 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/ed its 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

121injection zone and confining system a nd 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 operat or can demonstrate that core retrieval is not possible and that such cores DATA are representative of conditions

at the well IN THE WELLBORE. The Direct or may require the owner or operator to core other formations in the borehole.

Basis for CCS Group Comments: The informa tion required should be sufficient to properly describe the injec tion 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 mu st take whole cores or sidewall cores of the injection zone and confining system and formati on fluid samples from the injection zone(s), and must submit to the Director a detailed report pr epared 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/ed its 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) PR IOR TO INJECTION WELL OPERATION,the owner or operator must record PROVIDE REPRESENTATIVE INFORMATION ON the

fluid FORMATION temperature, FORMATI ON 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 para meters. The phrase "representative information" prevents the operator from having to do all tests in all wells.

Individual Response: EPA disagrees that "reservoir pressu re" and "static fluid level" are redundant parameters. Although the st atic fluid level is equal to the bottom hole pressure, this may not always be identical to the reservoir pr essure. Additionally, measuring the static fluid level provides additional assurance that the r eading is accurate (or, provides the needed information in cases where a good reading is no t obtained). In addition, a static fluid level measurement provides information regarding th e 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/ed its to rule language

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)

122Comment: Rule Provision: 146.87(d)

Proposed CCS Group Recommendations: (d) At a minimum, the owner or operator

must dete rmine or calculate the following information concerning the injection and confining zone(s): (1) Fracture pre ssure; (2) Other physical and chemical characteristics of the injection and c onfining zones; and (3) Physical and

chemical characteristics of th e formation fluids in the injection zone.

Basis for CCS Group Comments: With th e exception of calculating fracture pressure, the requirements of this section appear re dundant to other requirements of prior sections. The fractur e 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/ed its 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 te sts to verify hy drogeologic 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 SH OULD BE BASED ON REPRESENTATIVE

HYDROGEOLOGIC

AND GEOMECHANICAL CHARACTERISTIC S OF THE INJECTION ZONE.

Basis for CCS Group Comments: Allows the us e of information such as leak off tests conducted during the drilling operation.

The results of a pump test (pumping flui d from the well) have no relevance for an injection well.

Deletion of the injectivity test would a llow the use of non-destructive methods to calculate fracture pressure.

123Individual Response: EPA clarifies that the owner or opera tor has the option of using the pump tests or injectivity tests specified at §146.87( e) depending on which w ould provide the most valuable information based on site-specific cond itions. Further, EPA disa grees that pump tests are irrelevant to determining injection zone properties. Depending on the characteristics or depth of knowledge of the confining a nd injection zone formations, pu mp 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) w ould 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/ed its 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 al l logging and testing by this subpart. The owner or operator must submit a schedule of su ch activities to

the Director UPON SPUDDING THE WELL and s ubmit any changes to the schedule 48 HOURS prior to the scheduled test.

Basis for CCS Group Comments: The cha nges reflect the re alities of rig scheduling and are fully consistent with current Class II requirements and practices.

Individual Response: EPA disagrees that the 30-day notif ication requirement is unreasonable. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide mu ch 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 ab ility to be involved.

Letter ID: 0190 Comment ID: 24467 Letter Lines: 2714 to 2754

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 injec tion pressure does not exceed 90 perc ent of the fracture pressure of the injection zone so as to assure that the injection does not initiate new fractures or propag ate existing fractures in the injection

124zone. In no case may injection pressure initiate fractures in the confining zone(s) o r cause the movement of injection or formation fluids that endangers a

USDW. THE OWNER OR OPERATOR MUST CO MPLY WITH A MAXIMUM INJECTION

PRESSURE

LIMIT APPROVED BY THE DIRECTOR A ND 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 SHEA R 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 conc erned about three aspects of proposed section 146.88(a), governing injection pressure lim itations. First, it "restricts" fractures in the injection z one "except during stimulation" rather than focusing on maintaining the integrity of the confining zone, which is what really matters for protecti ng 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 co ncerns by focusing on maintaining the integrity of the confining zone and incl uding tensile failure and shear failure as transmissivity concerns. It calls fo r additional geomechanical studies of

tensile failure and shear failu re only "where appropriate" because there will be ocations where experience or existing information will provide sufficient

evidence to avoid the need for additiona l studies. The need for conducting additional tests and for determining which tests would be accepta ble is left to

the Director’s discretion.

This is the same recommendation as pr esented by the multi-stakeholder group, in which the Carbon Sequestrati on Council participated.

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

125based on the fracture pressure of the injection zo ne, the limit is site-sp ecific and not arbitrary. EPA emphasizes that injection pressure limits ar e important to protect against fracturing of the confining zone, and that the requ irement at §146.88(a) that the pressure in th e 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 Dire ctor determines, based on a review of the information collected as part of site characterization, th at a lower injection pr essure 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 pr ocess, owners or operators must submit data about the geology of the site, as specified at §146.82(a), includ ing data on known or suspected faults and fractures and geomechanical informati on on fractures, stress, du ctility, rock strength, and in situ fluid pressures w ithin the confining zone. The Di rector 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 requireme nt for the owner or operator to submit data on known or suspected faults and fractures and inform ation on the seismic history of the site will inform the determination of an appropriate pressu re 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 approach es for characterizing the regional geology and hydrogeology of a proposed site and performing the necessary geochemical, geomechanical, and geophysical analyses of the injection and confin ing zone. EPA is also developing guidance for primacy agencies that will include recommended a pproaches for evaluating owner or operatorsubmitted data in setting permit conditions. The gu idance 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/ed its to rule language

Comment Code: 4100 2.4.1 Injection parameters

Comment: Rule Provision: 146.88(b)

Proposed CCS Group Recommendations: (b) Inj ection OF THE CO2 STREAM between the outermost casing protecting USDWs a nd the well bore is prohibited.

Basis for CCS Group Comments: Routine inject ion 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 remedi al options that

could be useful.

126Individual Response: EPA retains the provision as propos ed, 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/ed its to rule language

Comment Code: 4100 2.4.1 Injection parameters

Comment: Rule Provision: 146.88(c)

Proposed CCS Group Recommendations: (c) Th e owner or operator must fill the annulus between the tubing and the long st ring 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 expe rience with the Class II UIC program does not support this requirem ent as proposed by EPA.

Positive annular pressure that exceeds th e operating injection pressure is not necessary because a leak from tubing to annulus does not have the same implications as in a Clas s 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 belie ves this requirement is appropriate for Class VI wells given the potential high volumes and superc ritical 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/ed its 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.

127Letter ID: 0190 Comment ID: 24471 Letter Lines: 2787 to 2814

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 de vices to monitor: the inje ction pressure; the rate, volume, and temperature of the carbon dioxide stream and . THE OWNER OR OPERATOR MUST REGULARLY MONITOR the pre ssure on the annulus between the tubing and the long string casing a nd annulus fluid volume and . THE OWNER OR

OPERATOR must install and us e alarms and automatic down

- hole shut-off systems, designed to alert the operato r and shut-in the well when operating parameters such as injection rate, inje ction pressure, or other parameters approved by the Director diverge beyond ra nges and/or gradients specified in the permit;

Basis for CCS Group Comments: Over-pressu re protection is best achieved by ensuring compatibility of the casing/tubi ng material design strength with the surface injection (compression) system. Down-hole shut-in devices are not appropriate for this application. These devices are installe d 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 th e packer). Additionally

these devices create a rest riction on running other tool s like logging tools in

the well and therefore could limit an operators ability to do required monitoring and diagnostic work. Lastly, th ese 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 disrup tive 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 possi bility of failure, e.g., due to overpressurization as suggested by the commenter. EP A 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 sy stems, as required at §146.88(e), is necessary to ensure protection of USDWs from endangerm ent from the risks asso ciated 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 believe s, however, that if the shut-off system is not deployed until

128the 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 requ ire getting the device to the site, setting up a rig, and deploying the device down the well, a si gnificant 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 a ll cases to ensure prot ection of USDWs from endangerment. Instead, the final rule, at §146.88(e)(2 ), requires that owne rs 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 requ ires, at §146.88(e)(3), that owners or operators of offshore wells

within State territorial waters instal l 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/ed its 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 discove red, the owner or operator must immediately investigate and identify as expeditiously as possible

the cause of the shutoff . If, upon such investigati on, the well appears to be lacking mechanical integrity, or if monitoring required un der paragraph (e)

of this section otherwise indicates thatthe well may be lacking mechanical integrity, the owner or operator must:

Basis for CCS Group Comments: Revisions ma de 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 auto matic surface shut-off devices. The rule affords

Director's discretion to mandate automatic down-hole shut-off devi ces 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 auto matic 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/ed its to rule language

Comment Code: 4000 2.4 Proposed Injection Well Operat ing Requirements (40 CFR 146.88)

129Comment: 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 triggere d or a loss of mechanical integr ity is discovered." Therefore the notice required at §146.88(f)(3) must be provide d 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 re sponse to potential USDW endangerment.

Letter ID: 0190 Comment ID: 24474 Letter Lines: 2837 to 2841

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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/ed its to rule language

Comment Code: 4520 2.5.1 Continuous internal mechani cal integrity monitoring (seeking comment)

Comment Code: 4720 2.7.2 Operational record keeping and reporting

Comment: Rule Provision: 146.89(b)

Proposed CCS Group Recommendations: (b) To evaluate the absen ce of significant leaks under paragraph (a)(1) of this s ection, owners or operators must, following an initial annulus pressure test, continuously monitor AND RECORD AT

LEAST DAILY, ANNULUS PRESSURE A ND VOLUMES OF FLUID ADDED TO OR

REMOVED FROM injection pressure, rate, inj ected volumes, and pressure on the annulus

130between the tubing and long stem stri ng casing and annulus fluid volume as specified in §146.88 (e);

Basis for CCS Group Comments: We recomm end continuous monitoring, but do not find continuous recording necessary as Class II re quirements have proven

sufficient. The alternative of continu ous monitoring, which will alert operator to any problems, and daily recording to al low 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 r ecord them electronically in a computer system. 40 CFR §146.91(a)(2) requires that monthly averages of th e 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/ed its 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 si gnificant fluid movement under paragraph (a)(2) of this section USING A METHOD ACCEPTABLE TO THE DIRECTOR (E.G.

INCLUDING

DIAGNOSTIC SURVEYS SUCH AS O XYGEN-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 re gular monitoring of annular pressure which could indicate leakage.

We recommend deletion of subsection (3) be cause it would require that the tubing be pulled at significant cost and risk of uncontrolled releases.

Individual Response: EPA believes that the MITs descri bed in 146.89(c) of the rule (an approved tracer log or temperatur e or noise logs) are effective me thods to demonstrate external

131MI, provide an important early warning of potenti al 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 th e 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 th at it can be used to determ ine the presence or absence of corrosion of the long-string casing, and is required if the Director determin es that it is necessary based on site-specific information. EPA has revi sed the final GS rule to require that the frequency of the casing inspection log must be specified in the approve d 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/ed its 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/ed its to rule language

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment)

Comment: Rule Provision: 146.90 [I ntroductory text]

132Proposed 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 MONI TORING 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 WI TH 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 m onitoring wells should be carefully considered since each well introduces a pot ential pathway for fluid movement. In addition the cost of adding multiple we lls could create a barrier to CCS development, while providing limited info rmation 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 furthe r 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, includi ng the testing and monitoring pl an. The guidance can be found on EPA’s website at http://water.epa.gov/type /groundwater/uic/we lls_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 a nd USDWs or other layers above the confining zone. Such construction technologies exist and have been us ed 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 inje cted 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 constr uction that will include reco mmendations 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

133Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 chem ical and physical ch aracteristics;

(b) (2) Installation and use, except duri ng well workovers as defined in section 146.88(d), of continuous monitori ng devices (INCLUDING DIGITAL DEVICES CAPTURING PERIODIC DATA) to monitor inj ection 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 TH E 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 FO R 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. Experi ence with CO2 EOR strongly shows that daily monitoring of most of these paramete rs 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 pressu re 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 cr itical to immediately identify corrosion-related well mechanical integrity loss. Class VI inje ction wells must be equipped with dedicated computer-based continuous pre ssure monitoring devices (in con cert with the Director-approved shut-off systems required for GS wells), which t ypically take readings several times per second and record them electronically in a computer system..

134EPA believes that a frequency of fi ve 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 Direct or may require more fre quent pressure fall-off tests at a specific project if n ecessary, based on site-specific circ umstances. Pressure fall-off tests may be conducted in conjunction with other well performance te sts (i.e., mechanical integrity testing) to ensure safe and effective opera tions. All monitoring da ta 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 th e 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 comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisi ons to the GS rule. See the final rule and preamble for further discussi on 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/ed its 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 PR ESSURE CHANGES IN AN APPROPRIATELY

POROUS AND

PERMEABLE FORMATION OVERLYI NG THE CONFINING ZONE.;

(2) THE USE OF INDIRECT, GEOPHYSIC AL 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 Q UALITY IN AN APPROPRIATELY POROUS

AND

PERMEABLE FORMATION OVERLY ING THE INJECTION ZONE;

(4) PERIODIC MONITORING OF WATER Q UALITY IN ONE OR MORE USDWS;

c (5) Corrosion monitoring of the we ll materials for loss of mass, thickness, cracking, pitting and other signs of corrosion performed and recorded

AT LEAST on a quarterly WHICH MAY BE MODIFI ED TO BE LESS FREQUENT AS

135APPROVED 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 we ll 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 INSPECT ING THE MATERIALS IN THE LOOP; or

(3) (III) Using an alternative method, MA TERIALS, 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 shoul d be no need for corrosion monitoring of most injected CO2 streams because t hose 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 c onstruction and characteristics of the injected CO2 stream and other factors.

The corrosion provisions are in cluded in subsection (c)(5).

Individual Response: EPA believes that quarterly corros ion monitoring of GS wells is necessary. CO2 in the presence of water (incl uding 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 a nd a limited number of field studies have investigated and

characterized the effects of carbonic acid on well materials. La boratory studies (e.g., Kutchko et al., 2007; Kutchko et al., 2008) cons istently identify al terations (typically carbonation) of cement

as the result of interactions betw een cement and CO2-saturated brine.

136Currently, there are only a few analyses of cemen t from wells that have been in prolonged

contact with CO2 in actual fiel d (down-hole) conditions. Evaluati on of cement from a well at the Scurry Area Canyon Reef Operator s Committee (SACROC) site s howed alteration, but did not show degradation that compromise d the structural integrity of th e 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 addre sses the effects of corrosion of st eel tubing and pipes. Lopez et al. (2003) noted that 60 percent of oilfield failures are re lated to the effects of carbonic acid from produced brines on carbon and low alloy steels.

Laboratory investigation of cement alteration/de gradation is an ongoing re search area. Few fieldbased studies have been completed to date. The laboratory and field stud ies currently available suggest that corrosion problems can be managed; however, there is no t a large enough body of research to rule out potentia l corrosion problems of steel co mponents of injection wells. The IPCC (2005) report on carbon dioxide capture an d storage reviewed oil and gas industry experience with gas injection we lls, close industry analogues to CO2 injection wells. The report stated that, while the design of CO2 injection we lls will be very similar to gas injection wells, most down-hole components of the CO2 injecti on wells will “need to be upgraded for higher pressure ratings and corrosion resistance.” Give n 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 th at corrosion monitoring in the down-hole environment is justified. For thes e reasons, the final ru le 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 pressu re 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 pr ovide 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 mode ling, evaluate predictions of plume movement, and target additional geochemical and surface monitoring needs.

EPA also believes that the ground water geoc hemical 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/ed its to rule language

137Comment 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 thr ough the confining zone or additional

identified zones:

(1) The location and number of monitoring wells must be based on specific information about the geologic sequest ration project, including injection

rate and v olume, geology, the presence of ar tificial 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 model ing results in the area of revi ew evaluation required by § 146.84(b);

Individual Response: EPA did not make the suggested cha nges, but agrees that monitoring plans and methods need to be site-specific a nd based on baseline data and data collected throughout operations. EPA believe s that the monitoring requirements for GS sites at §146.90 provide an appropriate level of flexibility in structuring a te sting and monitoring plan that protects USDWs from endangerment.

The final regulation provides for flexibility in: 1) methodologies used to co llect these data, 2) the spatial resolution at which the data should be co llected, 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, inject ion 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 exis t for complying with other requirements, such as tracking the positio n of the plume and pressure front within the injection zone.

Flexibility is also provided re garding how to monitor for the sp ecific data required by the final rule. The testing and monitoring plan is develope d by the owner or operato r 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 reco mmended approaches for implem enting a testing and monitoring plan, including pre-operational geophysical logging and testin g of injection wells, MITs, injection well testing during ope ration, groundwater quali ty monitoring, tracking the CO2 plume and pressure front, and soil gas and surface ai r monitoring which may be required by the UIC

138Director 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/ed its 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 de monstration of external mechanical integrity pursuant to § 1 46.89(c) at least once per y ear throughout the duration of the geologic sequestration project;

(f) A pressure fall

- off test at least once every fi ve 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 discussi on 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/ed its to rule language

Comment Code: 4650 2.6.5 CO2 plume and pressure fr ont 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 t he confining zone or using indirect, ge ophysical techniques (e.g., seismic, electrical, gravity, or electr omagnetic surveys and/or down

- hole carbon dioxide detection tools);

Basis for CCS Group Comments: Monitoring ou tside of the injection zone provides little information of value for tracking and monitoring the injected plume. Examples of how to test and monitor coul d be included in the Preamble but need

139not 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 opera tors 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 moveme nt 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 de tect movement of the pressure front unless a breach of the confining zone occurs. EPA believes that monitori ng using wells in the inje ction zone (i.e., that penetrate the confining zone) can be safely performed if the wells are constructed to prevent flow between the injection zone a nd USDWs or other layers above the confining zone. Such construction technologies exist and have been us ed 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 performi ng 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 ch anges are occurr ing above the confining zone due to CO2 leakage. Monitoring al so identifies needed re medial actions, provides inputs for AoR reevaluation modeling, and ta rgets additional geochemical and surface monitoring needs. Knowledge of th e 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 ma y be a need for more or different monitoring schemes (which may include monitoring in the conf ining zone), and adds that it is important to balance the need for adequate monitoring that ensures USDW protection from endangermentagainst too many artificial penetrations which could serve as conduits for fluid migration. Sitespecific testing and monitoring plans should desc ribe the proposed monitoring regime, which must be approved by the Director. Flexibility is also provided re garding how to monitor for the sp ecific data required by the final rule. The testing and monitoring plan is develope d by the owner or operato r 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 mon itoring to assist owne rs or operators and Directors in evaluating requi rements under §146.90, including pr oposed monitoring plans. The guidance describes available technologies a nd recommended approaches for implementing a testing and monitoring plan, including pre-ope rational geophysical l ogging and testing of injection wells, MITs, injecti on well testing during operation, groundwater quality monitoring, tracking the CO2 plume and pressure front, a nd soil gas and surface air monitoring which may be required by the UIC Director for specific GS projects. Th e guidance can be found on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_se questration.cfm.

140Letter ID: 0190 Comment ID: 24484 Letter Lines: 3038 to 3054

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 movem ent 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 g as monitoring must reflect base line data and the monitoring plan must include how the proposed monitoring will yield useful information on the

area of review delineation and/or co mpliance with standards under 40 CFR

144.12;

Basis for CCS Group Comments: In most s ituations soil and air monitoring does not provide an effective me thod of protecting USDWs.

Individual Response: EPA acknowledges that air and soil gas monitoring to ensure USDW protection is not necessary at a ll GS sites and agrees that the decision to use surface monitoring and the selection of monitoring methods for th e purpose of USDW protection will be sitespecific.

The Agency believes that surface air and soil ga s monitoring, when coupled with subsurface monitoring, may be appropriate at some GS projects to ensu re USDW protection. EPA also acknowledges that surface air a nd soil gas measurements are subj ect to variabili ty 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 thei r use. The decision to use surface monitoring and

the selection of monito ring methods will be site-specific (e.g., may be influenced by geology, injection depth, and operational conditions) and must be based on poten tial risks to USDWs

within the AoR.

In the final rule, at §146.90(h), the decision to re quire such monitoring as an additional measure to ensure USDW protection rests with the Direct or as a means of identif ying leaks that may pose a risk to USDWs and informing emergency notifi cation of a Class VI owner or operator and UIC Director in the event of a USDW endangerm ent, 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/ed its to rule language

141Comment 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, nece ssary to support, upgrade, and improve computational modeling of the area of review eval uation required under § 146.84(b) and to determine compliance with st andards under 40 CFR 144.12; and

(j) A quality assurance and surv eillance 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 furthe r 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/ed its 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) Se mi-annual OR LESS FREQUENT AT THE

DISCRETION OF THE DIRECTOR reports containing:

Basis for CCS Group Comments: Over the lif e of the project, the Director may decide that less reporting is acceptable

Individual Response: EPA is retaining the semi-annual reporti ng requirement in the final rule at §146.91(a) in order to ensure that permitting author ities can maintain proper oversight of GS projects, particularly in the early stages of rule implemen tation and deployment of GS technologies. The Agency also clarifies that pe rmitting authorities may choose to require more frequent reporting, at the discre tion 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 regula ting GS. The Agency plan s to, every six years, collect and review data on GS projects, incl uding operational data, to determine whether the appropriate amount and types of information a nd appropriate documentation are being collected,

and to determine if modifications to the re quirements are appropr iate or necessary.

142Letter ID: 0190 Comment ID: 24487 Letter Lines: 3077 to 3085

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4720 2.7.2 Operational record keeping and reporting

Comment: Rule Provision: 146.91(a)(1)

Proposed CCS Group Recommendations: (1) Any SIGNIFICANT changes to the physical,

chemical and other relevant characteristi cs of the carbon dioxide stream from the proposed operating data;

Basis for CCS Group Comments: (1) Technica l clarification. Si gnificance can be determined by a statistical analysis of the data. Rules should recognize that

there will be minor va riations in many data sets over time.

Individual Response: EPA retained this provision as pr oposed. 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 toconsistently 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 o ccurrences, and that information will aid in his/her

determination of whether these indi cate 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/ed its to rule language

Comment Code: 4720 2.7.2 Operational record keeping and reporting

Comment: Rule Provision: 146.91(a)(3) & (4)

Proposed CCS Group Recommendations: (3) A de scription 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 ev ent which triggers a shutdown device required pursuant to §146.88(e) and the response taken;

Basis for CCS Group Comments: EPA should c onsider some significance threshold on reporting these events to avoid reporting events th at would be of limited interest or consequence.

Individual Response: EPA retained this provision as pr oposed. The final rule at §146.91(a)(3) requires reporting of all exceedances of operating parameters. EPA disagrees with the suggestion

143to 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 toconsistently 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 o ccurrences, and that information will aid in his/her

determination of whether these indi cate 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/ed its to rule language

Comment Code: 4720 2.7.2 Operational record keeping 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/ed its to rule language

Comment Code: 5100 2.8.1 Injection well plugging activ ities (seeking comment) (40 CFR 146.92)

Comment: Rule Provision: 146.92(a)

Proposed CCS Group Recommendations: (a) Prio r to the well plugging, the owner or operator must flush each Class VI injec tion well with a buffer fluid, determine bottomhole reservoir pressure, and perform a final EXTERNAL mechanical integrity

test OF ANY RELEVANT WELLBOR E MATERIALS REMAINING.

Basis for CCS Group Comments: Many of the co mponents that would be tested by an

internal MIT are removed or test ed during the plugging process.

Rule Provision: 146.92(b)

Proposed CCS Group Recommendations: Support the proposed language.

144Basis for CCS Group Comments: Agree with EPA’s rationale.

Rule Provision: 146.192(b)(2) & (5)

Proposed CCS Group Recommendations: (2) Appr opriate testing methods to ensure FINAL EXTERNAL mechanical integrit y 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 co mponents that would be tested by an

internal MIT are removed or test ed 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 th e 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 pot entially corrosive nature of CO2 when it is in contact with water, that the re quirement that the material must be compatible with the CO2 stream is appropriate. Th e 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/ed its to rule language

Comment Code: 4730 2.7.3 Reporting associated with closur e and post-injection site care

Comment Code: 5100 2.8.1 Injection well plugging activ ities (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/ed its to rule language

Comment Code: 4730 2.7.3 Reporting associated with closur e and post-injection site care

Comment Code: 5100 2.8.1 Injection well plugging activ ities (seeking comment) (40 CFR 146.92)

145Comment: Rule Provision: 146.92(d)

Proposed CCS Group Recommendations: (d) Pl ugging report. Within 60 days after plugging the owner or operator must s ubmit a plugging report to the Director.

If the semi

- annual report is due l ess 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 th e owner or operator and by the person who performed the plugging operation (if ot her 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 afte r 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/ed its 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 t o be approved by the Director. SHALL CONTINUE TO CONDUCT

MONITORING AS SPECIFIED IN THE DI RECTOR-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 change s to §146.93(b)(3)

Individual Response: EPA disagrees with the suggested ch anges, and disagrees that the postinjection monitoring period should be strictly pe rformance-based. The Agency agrees that there

will be limited circumstances where it can be dem onstrated 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 en sures the protection of USDWs. However, EPA anticipates that a default timeframe for post-injecti on 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 base d 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 provi sion that the Director may, at his or her

146discretion, shorten the post-inj ection site care timeframe if the owner or operator can demonstrate that the GS project does not pose an endangerment to USDW s, as specified in §146.93(b)(2). Such a demonstration will be site-s pecific, 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-enda ngerment of USDWs will be demonstrated throughout the post-injec tion site care period.

Letter ID: 0190 Comment ID: 24494 Letter Lines: 3162 to 3180

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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) T he 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 diox ide plume and associated pressure

front at site closure as de monstrated in the area of review evaluation required under § 146.84(b);

(iii) A description of post

- injection monitoring locati on, methods, and proposed frequency; and

(iv) A proposed sche dule for submitting post

- injection site care monitoring

results to the Director.

Basis for CCS Group Comments: Revisions here reflect change s 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 furthe r 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/ed its to rule language

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

147Comment: 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 clos ure plan. EPA is requiring that, upon the cessation of injection, the owner or operator submit an amended post-inje ction site care and si te 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/ed its to rule language

Comment Code: 4730 2.7.3 Reporting associated with closur e 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 owne r 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 clos ure plan. EPA is requiring that upon the cessation of injection, the owner or operator submit an amended post-inje ction site care and si te 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 cl osure plan throughout the injec tion phase. EPA does not expect that changes to this plan would be implemente d until injection operations cease. EPA envisions that owners or operators would take into accoun t similar considerations that guide updates to other project plans, e.g., monito ring and operational data and resu lts 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 revise d the text at §146.93(a)(4) as follows: "At any time

148during the life of the geologic sequestration pr oject, the owner or ope rator may modify and resubmit the post-injection site car e and site closure plan for th e Director’s approval within 30 days of such change."

EPA is issuing guidance on development and upda ting of the GS project plans, including the post-injection site care and site closure plan. Th e guidance will be available on EPA's web site at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

Letter ID: 0190 Comment ID: 24497 Letter Lines: 3197 to 3216

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 injecti on 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 al so reconsider its proposed 50-year default period for post-injection site ca re. 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 determin ing 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, geologi c factors, and relative risk of the projec t. Such criteria are provided in our edits to §146.93(b)(3).

Individual Response: EPA disagrees that a post-injection si te care timeframe of 50 years is

excessive in most cases or arbi trary. EPA proposed a default post-in jection site car e 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 "Computationa l Modeling of Underground Injection of Carbon

Dioxide for Determination of Area-of-Review a nd Potential Risk to Underground Sources of Drinking Water." EPA assessed various default timeframes based on additional review of research studies and evaluation of public commen ts. While numerous commenters suggested that EPA shorten the monitoring timeframe, none of the commenters provided suffi cient data or other evidence to warrant a change in the proposed timeframe. While the 10- or 30-year timeframe

149suggested by some of these commenters may be within the timeframe suggested in some studies, EPA believes that the potential risks of endange ring USDWs will likely no t decline within these timeframes and available data, including da ta submitted by commenters, do not support a different default timeframe. However, EPA acknow ledges 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 pos t-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 ensu res non-endangerment of USDWs pursuant to requirements at §146.93(c).

EPA believes however, that to ensure USDW protection from enda ngerment, 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 prot ective 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 car e 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 ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-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/ed its 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 operato r can request and

demonstrate to the satisfaction of th e Director before 50 years, based on

m onitoring and other site

- specific data, that the ge ologic 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 monitori ng, THE DIRECTOR SHALL APPROVE THE

150REDUCTION. or may authorize site closur e 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 reta ins 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/ed its 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 DEMONS TRATE TO THE DIRECTOR, BASED ON MONITORING, OTHER SITE-SPECIFIC DATA, AND MODELING THAT IS REASONABLY CONSISTENT

WITH SITE PERFORMANCE, THAT NO ADDITIONAL M ONITORING 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 UNDERSTA NDING 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 CO 2 PLUME; (III) THAT THERE IS NO

SIGNIFICANT LEAKAGE OF EITHER CO2 OR DISPLACED FORMATION FLUIDS THAT

IS ENDANGERING USDWS; (IV) THAT THE INJE CTED OR DISPLACED FLUIDS ARE NOT

EXPECTED

TO MIGRATE IN THE FUTURE IN A MA NNER THAT ENCOUNTERS A POTENTIAL

LEAKAGE PATHWAY INTO A USDW; (V) THAT THE INJECTI ON WELLS AT THE SI TE 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

151WELLS 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 c ounterproductive. A straight performance standard is preferab le to this or any other fixed time period because it provides a clearer standa rd and an incentive to maximize the understanding of site and proj ect 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 pr oject poses no threat of endangerment to USDWs-plumes that are still moving may, nonetheless, remain contai ned. 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 pr oposal below provides specific guidance on what the operator must show.

We recommend the standard in the propos ed alternative language for section 146.93(b) below because it sets forth detail ed criteria, all of which must be satisfied, to demonstrate that the site doe s not pose an endangerment to USDWs. The specific criteria listed in our propos al will serve to pr ovide 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 obtaini ng site closure based upon particular site characteristics and is, therefore, reasonably applicable to any storage site as opposed to a standard based up on a fixed-duration. Furthermore, it is more stringent than a purely discretiona ry approach because it establishes specific criteria that must be shown before site clos ure may be granted. We believe this language, which is an extens ion of work done by the World Resources

Institute and the Ground Water Protection C ouncil, avoids the noted shortcomings and provides stronger protection for USDWs.

This is the same recommendation as pr esented by the multi-stakeholder group, in which the Carbon Sequestrati on 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 cl osure plan. EPA also believes that periodic reviews and updates, wh ere 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 requi rements in the final GS rule incorporate a combination of a fixed timeframe and a performance standard ap proach. The final GS rule offer owners or

152operators flexibility regarding th e duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthe n the PISC timeframe during th e post-injection period based on site-specific data, pursuant to requirements at §146.93(b); or (2) a ffording 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 appropr iate if it ensures nonendangerment of USDWs pursuant to requirements at §146.93(c).

EPA believes that a default post-injection site car e 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 ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-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 propo sed well plugging plans a nd post-injection site care and site closure plans under §146.92 a nd §146.93. The guidance describes recommended approaches for how an owner or operator coul d plug injection and monitoring wells, perform post-injection monitorin g, demonstrate the appropr iateness 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/t ype/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/ed its 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-injecti on timeframe (seeking comment)

Comment: Rule Provision: 146.93(b)(4)

Proposed CCS Group Recommendations: (4) If such a demonstration can not be made (i.e., if the carbon dioxide plume and pre ssure 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 n ecessary with 50-year period deletion.

Individual Response: As described above, EPA believes that to ensure USDW protection from endangerment, a default timeframe for post-injecti on site care is necessary in most cases. A 50- year post-injection site care ti meframe represents a reasonable and protective monitoring period

for most GS sites based on a review of res earch studies, industry reports, and existing environmental programs, and ev aluation of public comments.

153Letter ID: 0190 Comment ID: 24501 Letter Lines: 3294 to 3298

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4730 2.7.3 Reporting associated with closur e 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/ed its 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 suppor t; 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/ed its to rule language

Comment Code: 4730 2.7.3 Reporting associated with closur e 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 opera tor must submit a site closure report within 90 days that must th ereafter be retained at a location designated by the Director. AFTER COMPLETION OF ALL CL OSURE OPERATIONS. The report must include:

(1) Documentation of appropriate inj ection and monitoring well plugging as specified in §146.92 and paragraph (c) of this section. The owner or operator

154must provide a copy of a survey plat which has been submitted to the local zoning authority designated by the Director. The plat mu st indicate the location of the injection well(S) relative to perm anently 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 re sponsibility 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 opera tor 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 a ppropriate for the post-injection and site closure period to ensure that data are availabl e 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) re quires 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 fina l rule retains these provisions.

Letter ID: 0190 Comment ID: 24504 Letter Lines: 3345 to 3359

155Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5800 2.13 Comments on emergency and re medial 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 pr ovide the Director with an emergency A RISK-BASED remedial response plan that describes actions to be take n 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 respons e plan should be based on a risk assessment and risk management appro ach 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 devel op regulations for all areas related to GS." 73 Fed. Reg. at 43495. Accordingly, th e nature and scope of any such plans will necessarily be limited to the extent of that authority.

Individual Response: EPA agrees that emergency and remedi al response plans should be riskbased, however, EPA did not make the request ed change. The Agency believes that the requirement to develop a site-spe cific emergency and remedial res ponse 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/ed its to rule language

Comment Code: 5800 2.13 Comments on emergency and re medial 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 st ream, 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 PR UDENT MANNER CONSIDERING

CIRCUMSTANCES.

(2) Take all steps reasonably necessa ry to identify and characterize THE

ENDANGERMENT POSED;

(3) Notify the Director or the designa ted representative within 24 hours OF

BECOMING AWARE OF TH E ENDANGERMENT; and

156Basis for CCS Group Comments: Technical clarifications.

Under some circumstances, an immediate ce ssation of injection c ould 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 critic al situations, time spent obtaining approval could adversely aff ect 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 clarifie s that the pressure front, as defined in §146.81, is a zone where the pr essure differential is sufficient to cause the movement of injected fluids or formation flui ds into a USDW. Therefor e, displaced formation fluids are implicitly included in the requirements for §146.94. EPA al so 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 USDW s, as required under §1421 of the SDWA, EPA expects the owner or operator to act preemptiv ely and not wait until endangerment has occurred. This language is consistent w ith existing UIC requirements fo r other well classes and EPA’s authority under the SDWA.

EPA clarifies that the Agency e xpects 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 or der to prevent the enda ngerment of USDWs, as required under §1421 of the SDWA, EPA expects th e owner or operator to act preemptively and not wait until endangerment has occurred. This language is co nsistent with existing UIC requirements for other well classes a nd EPA’s authority under the SDWA.

EPA clarifies that the 24-hour notification require d under §146.94(b)(3) begins when the owner or operator obtains evidence of possible endangerment. EPA believe s the rule language is clear on this requirement.

Since proposal, EPA has modified the final regu latory language at §146.94( d) to clarify what

constitutes a workover to address a well failur e (which invokes remedi al actions) and what

157constitutes a maintenance-type workover. For ma intenance-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 notifica tion could delay responses, EPA clarifies that the GS rule (at §146.94(b)) describes procedures owners or opera tors must take in emergency situations. Specifically, upon determining that there is a problem with the we ll that may endanger a USDW, the owner or operator must firs t cease injection, then take all steps reasonably necessary to identify and characterize any release, notif y the Director, and implement the approved emergency and remedial response plan, which ma y include a well workover. EPA believes that ceasing injection (which the ow ner or operator would do immediately and before notifying the Director) is the immediate action necessary to pr event 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 comm ent 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 ex amples to support recommendations where appropriate. As EPA moves to ward finalizing this rule, EPA should monitor state rulemaking to assess the extent to whic h 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 th e 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 clim ate change, EPA believes that provi ding states the flexibility to obtain primacy for Class VI wells independently of other well cla sses 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 integrat ion of GS activities

under SDWA into a broader framework for mana ging CCS. Furthermore, GS operations involve ancillary activities (e.g., pipeli ne operations, pore space ownership, land use rights, and surface access) for which states can call upon other authorit ies that exist at the state level (but outside UIC authority) to provide a more comp rehensive CCS management approach.

158The Agency believes that it is important for stat es to use their unique e fficiencies to promote adoption of this burgeoning and important tec hnology, while assuring that USDWs are protected from endangerment through the UIC regulatory framework. EPA believe s 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 longstandi ng 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 Cl ass under Section 1422. EPA will continue to discourage applications for pa rtial primacy for all other well types under Section 1422.

EPA clarifies that states should be able to obtain primacy for Cla ss VI wells independent of other well classes provided they devel op regulations that are at leas t as stringent as the minimum Federal requirements (e.g., permitting, inspec tion, 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 en sure that their GS programs integrate into national climate change priori ties and protect USDWs from endangerment.

Throughout the process of this rulemaking EPA ha s 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 classe s) may encourage states to take responsibility for implementation of a more comprehensive ap proach to managing CCS projects (e.g., capture, transportation, and geologic sequestration). EPA cons idered 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 in jection 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 CO 2 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 Cla ss 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

159discussion (MSD) group that would make this more explicit.

We also support the absence of an econo mic test for oil and gas reservoir "depletion." The MSD group has developed language for differentiating between wells in oil and gas reservoirs that s hould 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 transi tioning permits from Class II to Class VI. The guidance will assist Directors in de termining whether an injection project should be transitioned from Class II, where the prim ary purpose is oil and ga s 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 determin e whether a project should be regulated within the Class II or Class VI UIC pr ogram. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequest ration.cfm. For more information, please

see the discussion on transition of Class II well s 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 Federa l Register Cite: 146.81(c) EPA Preamble Question: 3. EPA seeks comm ent on the approach to grandfather construction requirements at the Director ’s discretion for existing Class I, Class II, and Class V wells seeking to c onvert to Class VI wells, and whether additional construction require ments would be necessary to prevent endangerment

to USDWs from the GS of CO2. EPA Notice 43502.

CSC Response: CSC strongly supports a regulat ory approach that would facilitate the transition of existing wells constructe d to Class I, Class II and Class V standards to GS wells regulated under pr ovisions of the propos ed rule. In all cases, such existing wells will have been permitted under conditions sufficient to protect USDWs and will have a demonstr ated 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 requirem ents. In particular, wells constructed

to current Class II standard s with demonstrated success in CO2 service should be eligible for grandfathering with minimal steps such as notification and permit modifications to add any additional requi rements necessary to address geologic containment of injected carbon dioxide st reams. 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 Federa l Register Cite: 146.81(c) EPA Preamble Question: 4. Additionally, EPA seeks comment on how the

160grandfathering approach for existing wells may affect compliance with the other requirements in its proposal. EPA Notice 43502.

CSC Response: All components of the exis ting wells with a proven record of performance should be grandfathered unless there are specific USDW endangerment concerns identified by the Di rector. See Comment above.

Individual Response: EPA agrees that many Class I, Cl ass 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 en gineered 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 ot her requirements (e.g., MITs, siting, monitoring, operational, and AoR requirements) should also be grandfathered. Following re-permitting, these projects must be subject to the operationa l, MIT, monitoring, reporting, plugging, and postinjection site care and site closur e requirements in the final GS ru le. 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 Re gister Cite: 144.6(f), 146.5, 146.81 EPA Preamble Question: 5. EPA is proposing to preclude the inje ction of CO2 for long-term storage into coal seams where they are above the lo wermost USDW. EPA requests comment on this propos ed prohibition. EPA Notice 43503.

CSC Response: CSC opposes this restricti on. Qualification of a formation for storage should be based on performan ce-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 geol ogy from one area of the country to another. Rather than impose an arbi trary limit based on the depth of the lowermost USDW or a specific minimum de pth restriction, EPA should follow its stated objective and use a performance stan dard that is clearl y spelled out and can be met with appropriate demo nstrations of containment.

Individual Response: The final GS rule does not categorica lly preclude or prohibit injection into any type of formation, including coal se ams. Instead, the requirements are designed to

161ensure protection of USDWs from endange rment 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 se ams and basalts, are typically shallow and above the lowermost USDW. EPA exp ects 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 demonstr ate that such injection can be performed in a manner that protects USDWs, as long as appropriate protec tions are in place. The Class V experimental technology well classification, may, in some instan ces be an appropriate permitting alternative. This decision should be informed through a di scussion 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 approa ch and aquifer exemptions for Class VI wells, please see the final rule and pr eamble, 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 Re gister Cite: 144.6(f), 146.5, 146.81 EPA Preamble Question: 6. The location a nd 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 CO 2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent example is the Salt Creek EOR pr oject in Wyoming, which has a USDW below the injection zone. Moreover, unde r the proposed rule, there are other measures that would provide real assura nce of formation integrity and require operators to demonstrate that their proj ect will not endanger USDWs, making the lowermost USDW restriction unnecessary.

In conjunction with this recommendation, CS C 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 ot her factors allow applicants to demonstrate that these sites can be suitable for geol ogical sequestration while preventing endangerment of USDWs.

Keeping these wells under Class V would allow EPA and the states to gain

162experience in developing suitable permitting requirements for such wells and to tailor those requirements until the agenci es are ready to adapt the Class VI regulations or other requir ements as appropriate.

Individual Response: EPA anticipates that some owners or operators will apply for Class V experimental technology permits for injection into formations in cluding shallow basalts, coal seams, salt caverns, and shales. These forma tions 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 guidan ce will be available on EPA's web site, at http://water.epa.gov/type/groundw ater/uic/wells_sequestration.cfm. EPA acknowledges that the Class V experimental technology we ll sub-classification may be a ppropriate for these projects, provided they are experimental in nature. EPA e xpects that, following the final GS rule, a limited number of experimental injection projects tes ting GS technology will continue. EPA anticipates that these projects will be small-scale and i nvolve limited CO2 volumes. However, if these projects become larger scale a nd are no longer experimental, they will need to be permitted as Class VI wells. The construction, operation, or ma intenance of any non-expe rimental 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, CS C 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 ot her factors allow applicants to demonstrate that these sites can be suitable for geol ogical 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 agenci es are ready to adapt the Class VI regulations or other requir ements 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 na ture and would be to test new technologies, and that EPA does not consider it appropriate to permit CO2 injecti on wells that are testing the injectivity or appropriateness of an individual fo rmation (e.g., as a prelude to a co mmercial-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 th e Class V experimental technology well classification to clarify perm itting for Class V wells. This addendum will address shifting of Class V experi mental projects to full-scale GS projects and the future use of

163the Class V experimental technology well s ubclass for research a nd 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 CO 2; purity standards for CO2

Comment: Rule Provisions or Federal Re gister 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 th at are not hazardous wastes as defined in 40 CFR Part 261. As a result, EPA’s proposed ru le would preclude th e injection of hazardous wastes in Class VI injection we lls. 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 concep t that Class VI wells should not be injecting hazardous wastes, but there are believed to be few, if any,

circumstances under which RCRA hazardous wa ste provisions would apply to CO2 streams. Current capture technologies under development are not likely to produce a CO2 stream that would ever m eet the definition of hazardous waste under 40 CFR 261. These CO2 capture technol ogies will yield a relatively pure CO2 stream, one that is unlikely to contai n 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 stream s will not be suscep tible to normal RCRA testing protocols because of the physic al characteristics of supercritical

CO2.

In addition, we are proposing some modi fications to EPA’s definition of CO2

stream in the rule. The modifications re flect 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 s hould not address the origins of the materials since that is beyond the scope of this regulation. Th e 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 st ored CO2 should not be arbitrarily prohibited; however, it is recognized that the presence of those impurities at sufficient concentrations may trigger th e applicability of other statutory limits or requirements. Determining the t ype and levels of impurities in the CO2 stream is " absent a compelling public or environmental health risk " best left

164to contractual negotiations between partie s in a CCS value chain as opposed to an arbitrary regulatory determination. The contracting parties are best able to evaluate the types of impu rities, their compatibility with the reservoir and equipment, and determine the acceptable leve ls of those impurities in the stored CO2. If there were ever any overriding pub lic interest in limiting either the type or level of contaminants, princi ples of cost-effectiveness and riskmanagement should guide the decision making process.

Individual Response: EPA understands that many CO2 str eams 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 in formation, and uncertainties remain about the expected concentrations of impurities from the va rious 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 standa rds 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 sour ce of the CO2 and its physical and chemical properties. Specifically, the GS rule requires the owner or operator to subm it 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 compatib ility of the CO2 stream with fluids in the injection zone and minerals in both the injection and the confini ng zones and the materials used to construct the well, per §146.82(c)(3). This info rmation 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 st reams that meet the definition of a hazardous waste under 40 CFR part 261, injection of a CO2 str eam 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 "authori ze" 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 pr event 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 unten able. EPA should remember that CERCLA

165liability will not only impact owners and operators of GS projects, but also hundreds, thousands, and even more nume rous 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 liab ility under CERCLA pursuant to whatever liability theories might be developed by future litiga nts seeking compensation for response and remediation costs incurre d in the cleanup of releases from geologic sequestration inj ection zones. EPA should recognize the si gnificant chilling effect CERCLA liability concerns will have on GS projects, and seize the opportunity in this rulema king 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 reque sts 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 poten tial CERCLA liabilities will have the potential to chill enthusiasm for undertak ing GS projects. EPA needs to respond clearly and positively to this concern by developing appropriate language in the regulations and permits to provide the cl arity and assurance needed to promote

continued research and deve lopment for GS projects.

Individual Response: As described above, whether the presen ce of hazardous substances in the CO2 may result in CERCLA liability from a se questration 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 lia bility, 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 CERCL A 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 outsi de the scope of the GS rule. Rather, the purpose of the GS regulation is to ensu re that, where deployed, GS is c onducted 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 id entify and characterize

166additional confining and containment zone s above the primary (i.e., lowermost) confining zone that could further impede vertical fluid movement and allow for pressure dissipation. EPA says that thes e layers could provide additional sites for monitoring, mitigation, and remediati on. EPA’s proposal w ould 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 th eir characteristics can provide inputs for predictive models, identify appropri ate monitoring locations, and improve public confidence in and acceptance of a proposed GS site. EPA specifically seeks comment on the merits of requiring th e 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 high ly protective of USDWs. Adequacy of containment must be de monstrated on a site-s pecific basis. By definition, an additional confining or cont ainment zone beyond is not necessary to prevent endangerment of USDWs, and w ould serve only to prevent the use of otherwise-appropriate GS reservoirs.

Individual Response: EPA retains the requirement to iden tify additional containment/confining zones, if required by the Di rector, as proposed (§146.83(b)). EPA clarifies that secondary confining zones are not required for all GS sites. EPA acknowledge s that such additional zones may not be needed in all circumstances, and clarif ies that this requirement is at the Director's discretion, based on his or her unde rstanding of a particular site . EPA believes that, in some situations, the presence of add itional 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 prov ide additional sites for monitoring, mitigation, and remediation. The Ag ency's decision is supported by commenters representing states, water associations, and an elec tric 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 unders tanding 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 Regi ster 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 condi tions and injection regime. EPA seeks comment on the use of modeling fo r AoR delineation. EPA Notice 43506.

CSC Response: Modeling is well developed technology that can readily simulate complex behavior of injected CO2. It s hould be one of the techniques used to

167delineate 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 nece ssary to adequately delineate the AoR. Some CO2 EOR projects have successfu lly operated for decades using only production data and pressure mapping, wh ich has in effect defined AoR.

Individual Response: EPA agrees that the oil and gas indus try has contributed to the state of modeling science, and anticipat es 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 equa tions, and scientific basis.

EPA clarifies that the model i nputs must include act ual 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 recalibr ated during subsequent AoR reevaluations,

which must account for all avai lable monitoring and operational data, as required at §146.84(e).

EPA encourages and expects owners or operato rs to use the most appropriate multiphase computational models available to determine th e AoR. However, EPA doe s 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 appropri ate for a particular GS project.

EPA anticipates that modeling technology will con tinue 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, resu lting 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 Federa l Register Cite: 146.84 EPA Preamble Question: 12. In some cases, ow ners 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 ma y prevent full evaluation of model results (e.g., NRC, 2007). Severa l popular codes in the petroleumreservoir engineering discipline are propr ietary 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

168clearly disclose the code assumptions, rele vant equations, and sc ientific basis. EPA seeks comment on allowing the use of pr oprietary models for GS sites. EPA

Notice 43507.

CSC Response: Use of proprietary models should be allowed. EPA’s Confidential Business Information requirements should a pply to any proprietary model used.

Individual Response: EPA agrees that some of the availa ble 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 sa tisfaction, the code assumptions, re levant equations, and scientific basis. EPA acknowledges that several proprietary models have been used by petroleum-reservoir engineering professionals as we ll as in peer-reviewed studies to model CO2 sequestration. EPA

adds that its Confidential Business Informati on requirements at 40 CFR 144.5 will apply to the use of proprietary models. Information includin g model assumptions and equations are used by

the Director to inform his/her decision to issu e 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 Federa l Register Cite: 146.84 EPA Preamble Question: 13. EPA seeks comment on the applicability of computational fluid flow models for delin eating the AoR of GS sites. EPA Notice

43507.

CSC Response: Computational fluid flow mode ls 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 computati onal 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 th at is most appropriate for a pa rticular GS project. EPA adds

that its Confidential Business Information requirements at 40 CF R 144.5 will apply to the use of proprietary models.

EPA anticipates that modeling technology will con tinue 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, resu lting in increased protection of USDWs from endangerment.

169Letter ID: 0190 Comment ID: 24518 Letter Lines: 3659 to 3668

Comment Code: 3530 2.2.3.1 AoR reevaluation fre quency (seeking comment)

Comment: Rule Provisions or Federa l Register Cite: 146.84 EPA Preamble Question: 14. EPA seeks comm ent 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 ti me period, CSC recommends following a performance based approach that would re quire reevaluation of the AOR as, but only as, it is necessary, as determined by consideration of whether there are significant unexpected changes in injec tion parameters or monitoring results.

Individual Response: EPA agrees that site-specific fact ors should be considered in the reevaluation schedule, and notes that the AoR and corrective acti on plan must specify the sitespecific monitoring and operationa l conditions that warrant r eevaluation, 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 r eason to believe, based on site-speci fic information, that a five-year

reevaluation schedule is not su fficiently protective of USDWs. However, EPA believes that setting a minimum reevaluation frequency is appr opriate. 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 th at this revised frequenc y addresses commenters'

concerns about the inherent unc ertainties in modeling CO2 move ment, the emerging nature of GS technology, risk-based targeti ng of monitoring activ ities, and the unique nature of CO2 GS. In addition, the Director has disc retion to require more frequent AoR reevaluation if he or she has reason to believe, based on site-specific inform ation, that a five-year reevaluation schedule is not sufficiently prot ective 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 Federa l Register Cite: 146.84(f) EPA Preamble Question: 15. EPA proposes to allow a phased appro ach to corrective action but says this may not be appropriat e in all situations; therefore EPA is proposing that the Director have the discretion to decide to allow this approach, based on the unders tanding of relevant geol ogic and site conditions. EPA invites public comment on the merits and frequency of reevaluation of the AoR as well as the phased corrective acti on approach for GS wells. EPA Notice

43508.

CSC Response: CSC supports the EPA proposal. The phased approach allows the

170sound economic execution of the project ov er time without enda ngering 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 s upport 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, avoi ding delays in project start-up, allowing for use of future, improved corrective act ion 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 w ould need to review and amend the AoR and corrective action plan and follow the amended plan.

Regarding the comment that AoR reevaluation fre quency 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 protec tion of USDWs from endang erment and address the uncertainties inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure that a deliberate effort is made to verify, base d 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 Federa l 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 op posite 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 recogni zed that this is no t appropriate in all geologic settings. In some areas USDW s can extend to much greater depths than would be appropriate for setting of surface casing. Regulations should recognize these situations and allow a su rface casing setting depth that may not fully cover the USDWs.

Individual Response: Section 146.86(b)(3) requires that th e long-string casing extend to the injection zone and be cemented by circulating ce ment to the surface in one or more stages. It

171does 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 pr otected from endangerment, s ubject to the approval of the

Director. EPA notes that there ar e many potential ways to meet the requirement in deep wells, such as the use of staged cementing. See th e 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/we lls_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 Cl ass I municipal waste disposal wells. Some of these wells, which must meet the same cemen ting 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 provisi on, saying that it provides, at a reasonable cost, corrosion protection of the casing, prevents undesirable migration of fluids be hind the casing, provides support to the casing, and provides multiple ba rriers against endangerment of USDWs.

EPA recognizes concerns regardi ng construction of Class VI wells where the lowermost USDW is very deep. To further address comments on d eep 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 opera ting under injection depth waivers must comply with additional construction require ments to ensure that wells used to inject above or between USDWs are protective. See the discussion of the wa iver 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 Federa l 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 op posite a cemented interval. EPA Notice

43509.

Regarding packer setting depth, the dire ctor 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 beli eves that the use of tubing and packer in accordance with §146.86(c) will offer the best multiple-barrier protec tion of USDWs from endangerment. Additionally, EPA is developing gui dance on the construction of Class VI wells.

172This 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 Federa l Register Cite: 146.81(c) EPA Preamble Question: 17. EPA also seeks comment on how the proposed grandfathering provisions for existing we lls (construction requirements) may affect compliance with the above, proposed construction requirements. EPA Notice

43509.

CSC Response: By definition, the construc tion of previously-permitted wells has already been determined to be sufficient for protection of USDWs. Consequently, additional construction-related requireme nts should not be imposed in the absence of specific evidence of a constr uction-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), pr ovided the owner or oper ator 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, a nd post-injection site ca re and site closure requirements in the final GS rule. See the discus sion 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 Federa l Register Cite: 146.86 EPA Preamble Question: 18. EPA seeks comm ent on the merits of horizontal well drilling techniques for GS wells and th e applicability of well construction requirements discussed in th is proposal. EPA Notice 43509.

CSC Response: Drilling of directional a nd 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 horiz ontal or have horiz ontal sections.

173Individual Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appr opriateness of horizonta l drilling techniques for Class VI wells, and commenters representing energy companies, el ectric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously suppo rted the concept and provided many reasons why horizonta l 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 ensu re the protection of USDW s 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 Re gister 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 resist ant 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 re sistant as long as th e 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 expe rience 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 pr oper 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 reco very, 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 flexibil ity: 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 flui ds 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 co mponent 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.

174Letter ID: 0190 Comment ID: 24527 Letter Lines: 3746 to 3755

Comment Code: 4130 2.4.1.3 Appropriateness of using fractur ing for well stimulation (seeking comment)

Comment: Rule Provisions or Federa l Register Cite: 146.88(a) EPA Preamble Question: 20. EPA is request ing comment on the extent to which hydraulic fracturing should be allowed dur ing GS injection, and whether the use of fracturing for the purposes of well s timulation is appropriate. EPA Notice

43511.

CSC Response: The use of fracturing for s timulation is appropri ate 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 conf ining zone can be anticipated.

Individual Response: EPA agrees that stimulation, such as hydraulic fracturing, should be permitted in some situations, and the final rule a llows 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 injec tivity. 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 th e 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 wi ll 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 possi ble 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, w ill inform the Director's decision on whether hydraulic fracturing is accep table 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 re questing 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 fractur ing for stimulation and should set injection pressure limits to precl ude initiating, propagating, or opening avenues of release through fractures transecting the confining zone.

175Individual 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 a pproved by the Director (operators seeking to use stimul ation 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 Direct or in advance of any planned stim ulation 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 pr ovision at §146.88(a). EPA believes that the 90 percent requirement, which was suggested by st ate representatives and permit writers whom EPA consulted when writing the regulation, is a satis factory margin of safety for well operation.

In addition, to maintain the integrity of the c onfining zone, the final rule requires that, except during stimulation, the inj ection pressure not exceed 90 percen t 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 Federa l 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 protec tion is best achieved by ensuring compatibility of the casing/tubing material design strength with the surface injection (compression) system. Down-hol e 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 tubi ng at or near the ocean floor in the event that the tubing is se vered 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 inst all these devices deep underground (e.g. shortly above the packer). Additionally th ese devices would create a restriction on running other tools like l ogging tools in the well and therefore could limit an operator’s ability to do required m onitoring and diagnostic work. Lastly, these devices require periodic testing and maintenance which could require either pulling the device by wireline or by pulling the enti re tubing string depending on the type of device installed. Either of these activities would be disruptive and costly to th e 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

176operators of onshore Class VI wells install auto matic surface shut-off devices. The rule affords

Director's discretion to mandate automatic down-hole shut-off devi ces 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 inst all 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 Re gister Cite: 144.6(f), 146.5, 146.81 EPA Preamble Question: 23. EPA is aware th at the proposal to limit CO2 injection

to reservoirs below the lowermost USDW may preclude injec tion into certain geologic formations currently under cons ideration 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 re move a significant number of viable

formations from consideration. It has been shown that CO2 injection wells can be operated in an EOR context without endange ring 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 z one. Moreover, under the proposed rule, there are other measures that would pr ovide real assurance of formation integrity and require operators to dem onstrate that their project will not endanger USDWs, making the lowermos t USDW restriction unnecessary.

Individual Response: As described above, EPA acknowledges that there are limited circumstances where injection above the lowerm ost 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 pr ocess by which owners or operato rs can seek a waiver of the Class VI injection depth requirements for inje ction into non-USDW form ations 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 Re gister Cite: 144.6(f), 146.5, 146.81 EPA Preamble Question: 24. EPA is solicit ing comment on whether CO2 injection should be allowed into an injection zone above the lowermost USDW, when the

177Director determines that geologic cond itions (e.g., thousands of feet of intervening formations between the inj ection 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 evalua tion of performance based criteria. "Thousands of feet of intervening formati ons" 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 lowerm ost 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 pr ocess by which owners or operato rs can seek a waiver of the Class VI injection depth requirements for inje ction into non-USDW form ations 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 pur pose of Class VI injection, and under what conditions should such aquifer ex emptions be approved. EPA Notice 43512.

CSC Response: At this time, we do not recommend any specific need for new aquifer exemption criteria created becau se the existing crite ria are perceived to be sufficient to allow aquifer exemp tions 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 sequest ration 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 enda nger 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 lim ited 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

178expansions 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 expansi on 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 pr otected 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 Da ta 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 comm ent 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 de pth for injection of CO2. The primary consideration should be prot ection of USDWs. A requireme nt for a minimum depth suggests an intention by EPA to require injection of CO2 in a supercritical phase. Such a requirement is not appropr iate since there ma y 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 fo r 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 requir e that the CO2 be inject ed in a supercritical state. The final GS rule at §146.95 establishes a pr ocess by which owners or operators can seek a waiver of the Class VI injection depth requir ements 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 im pact on human health or ecosystems (seeking comment)

179Comment: 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 ecosy stems as they relate to USDWs. EPA

Notice 43513.

CSC Response: EPA should not mandate the us e of tracers. The potential value of tracers is uncertain and too limited to ju stify their use in the injection well context. Any use of tracers should be en tirely 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 th e use of tracers at all GS sites; however, the

Director has discretion to require their use if he/she determ ines 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 operat or and approved by the Director.

Letter ID: 0190 Comment ID: 24535 Letter Lines: 3864 to 3879

Comment Code: 4520 2.5.1 Continuous internal mechani cal integrity monitoring (seeking comment)

Comment: Rule Provisions or Federa l Register Cite: 146.89(b) EPA Preamble Question: 28. EPA’s proposal wo uld 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 in ternal 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 st rongly shows that daily monitoring of most of these parameters is adequate (e xceptions to this would be on a sitespecific basis). Recording should genera lly 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 le vel 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 inje ction wells), is importa nt given the potential corrosive impact of CO2 and impurities on well ma terials, 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

180monitoring is practicable, available, and is currently in fairly wi de use. At least one commenter indicated that the technology re quired for continuous monitori ng is currently available and should not present an undue cost burden. Continuous annulus monito ring is also conducted at the commercial-scaled carbon capture and geologic seque stration operation at the In Salah, Algeria natural gas plant where more than 3 million t ons 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 mont hly 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 Re gister Cite: 146,89(c), 146,90(e) EPA Preamble Question: 29. EPA seeks comm ent on the appropriate frequency of internal and external MITs for GS inj ection 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 extern al MIT is appropriate. The final GS regulation retains the requirement that owners or operators of Class VI wells must demonstrate injection well external mechan ical 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 fr om 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 inje ction, 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 in jection for GS are significantly larger than the volumes of CO2 injected for ER operations.

181In addition, a comprehensive review conducte d by EPA of MIT results from 1993 to 1998 found that Class I wells injecting corrosi ve fluids fail MITs at rates two to three times higher than those that inject non-corrosive fluids (USEPA 1999). Given the potentia l for CO2 to be corrosive (e.g., in the presence of water or aqueous formation flui ds), there is a potential risk factor for MIT failure and, for this reason, EPA be lieves that the tailored MIT requi rements 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 wh ether 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 te st integrity of the long string casing, packer, and tubing and to the extent pract icable, should test the integrity of the cement isolating the injection zone . There are many methods for conducting MITs. EPA should allow operators adequa te flexibility in selecting the appropriate methods for their specif ic situation. API RP90 provides good examples of various methods for detecti ng mechanical failures, managing those risks, and conducting MITs.

Individual Response: EPA believes that the MITs describe d 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 pr oblems 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 th e owner or operator to prepare and gain approval for a project-specific testing and monitoring pl an 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 met hods 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 Ag ency plans to collect and review data every six years on GS projects to determine whether the appropriate amount and types of information and appropriate documenta tion are being collected, and to determine if modifications to the requirements are appropriate or necessary.

182Letter ID: 0190 Comment ID: 24539 Letter Lines: 3898 to 3910

Comment Code: 4650 2.6.5 CO2 plume and pressure fr ont tracking (seeking comment)

Comment: Rule Provisions or Federa l Register Cite: 146.90 EPA Preamble Question: 30. EPA seeks comm ent on the requiremen t for monitoring of GS sites for the purpose of trackin g the location of the CO2 plume and associated pressure front over time. EPA Notice 43514

CSC Response: The amount of monitoring requ ired to track plumes and pressure fronts is not cost justified in comparis on with taking the necessary steps to demonstrate containment. The primary fo cus should be on making sure that the plume and formation fluid are contained w ithin the injection zone rather than trying to show the exact location of th e plume within that containment.

The frequency of monitoring should be dict ated by site-specific operational and geologic conditions comb ined 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 n eeded remedial actions, provide inputs for AoR reevaluation modeling, evaluate predictions of plume move ment, 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 th at GS projects are proceeding according to plan, provide sufficient information to the owner or op erator 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 de tect movement of the pressure front unless a breach of the confining zone occurs. EPA believes that monitori ng using wells in the inje ction zone (i.e., that penetrate the confining zone) can be safely performed if the wells are constructed to prevent flow between the injection zone a nd USDWs or other layers above the confining zone. Such construction technologies exist and have been us ed 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 performi ng 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 ch anges are occurr ing above the confining zone due to CO2 leakage.

EPA adds that all monitoring will be conducted pursuant to the approve d testing and monitoring plan, which should be based on site-specific info rmation about the site and planned operations.

Letter ID: 0190 Comment ID: 24540 Letter Lines: 3912 to 3922

183Comment Code: 4640 2.6.4 Pressure fall-off testing (seeking comment)

Comment: Rule Provisions or Federa l Register Cite: 146.90(f) EPA Preamble Question: 31. EPA’s proposal wo uld require that owners or operators perform a pressure fall-off test at le ast once every five years. EPA seeks comment on the use and frequency of pressu re 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 oper ational injection and after the first year of operational injection. Following th e first year, the fre quency 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 appropr iate 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 proj ect, if necessary based on sitespecific circumstances. Pressure fall-off tests ma y be conducted in conjunction with other well performance tests (i.e., mechanical integrity testing) to ensure sa fe 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 fr ont tracking (seeking comment)

Comment Code: 4655 2.6.5.1 Plume tracking techniques/ geophysical methods (seeking comment)

Comment: Rule Provisions or Federa l Register Cite: 146.90(g) EPA Preamble Question: 32. Based on inform ation evaluated to date, EPA believes that tracking the plume and pressure front is an impor tant companion step to address any uncertainties associated w ith initial AoR modeling and requests comment on this approach and more efficien t 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 modeli ng approach. Requirements to "track" plumes or pressure fronts would be extraordinarily burdensome and are not necessary, as extensive expe rience 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 wh ile there are similarities between injection of hazardous wastes for disposal (Class I) and GS (C lass VI), there are significant differences as well. Important unique considerations for GS in clude the buoyancy of CO2, its corrosivity when

184in 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 unc ertainty regarding the be havior of large volumes

of CO2 in the subsurface after injection. Given these characteristi cs of anticipated GS projects, EPA believes that plume and pressure front m onitoring at §146.90(g) are justified to provide early warning of any unforeseen fluid m ovement that might endanger USDWs.

The final rule (at §146.90(g)) requi res owners or operators to pe rform 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 met hods (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down- hole CO2 detection tool s) are also required unless the Director determines, based on site-s pecific geology that such methods are not appropriate.

EPA believes that pressure monitoring in th e injection zone is n ecessary 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 m odeling, evaluate predictions of plume movement, and target additional geoche mical 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 commen t on the appropriate amount and types of monitoring that should be conducted at a GS site. Specifically, EPA seeks comment regarding the usefulness of indi rect geophysical monitoring and surface air and soil gas monitoring. In addition, EPA seeks commen t 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. Select ion of monitoring types and frequency should balance the potential risks posed by the project w ith 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 us e 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

185protection is not necessary at a ll GS sites and agrees that the decision to use surface monitoring and the selection of monitoring methods for th e purpose of USDW protection will be sitespecific.

The Agency believes that surface air and soil ga s monitoring, when coupled with subsurface monitoring, may be appropriate at some GS projects to ensu re USDW protection. EPA also acknowledges that surface air a nd soil gas measurements are subj ect to variabili ty 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 thei r use. The decision to use surface monitoring and

the selection of monito ring methods will be site-specific (e.g., may be influenced by geology, injection depth, and operational conditions) and must be based on poten tial risks to USDWs

within the AoR.

In the final rule, at §146.90(h), the decision to re quire such monitoring as an additional measure to ensure USDW protection rests with the Direct or as a means of identif ying leaks that may pose a risk to USDWs and informing emergency notifi cation of a Class VI owner or operator and UIC Director in the event of a USDW endangerm ent, 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 Regi ster Cite: 146.90, 146.93(a), 146.94(a) EPA Preamble Question: 34. EPA is proposi ng that permit applic ations for GS sites include several plans not curr ently required under existing UIC regulations. These plans include a mon itoring and testing plan, an AoR and corrective action plan, and a post-injecti on site care and s ite 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. CS C is concerned that every modification of a plan may trigger a major permit modification, although it does not appear that current regulations would requi re 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 cons truction, operation, and closur e 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 monitori ng plan at the start of the project, particularly considering that these ac tivities will not occur for many years

186after the project starts.

Individual Response: EPA agrees with commenters that developing and following testing and monitoring plans is an important pa rt of assuring that a GS projec t 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. EP A clarifies that the final GS regulation includes a requirement th at the AoR be reevaluated at least every five years, and it specifies at §146.90(j) that the oper ator revise the testing and mon itoring plan to incorporate the

results of the most recent AoR reevaluati on 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 regulat ion at 40 CFR 144.39(a) identifies causes for modification of permits that would invoke the pu blic notification procedures at 40 CFR 124. In the final rule, EPA added text to §144.39(a)(5) that permit modificat ions would be required if the

Director determines that a modification is nece ssary 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 fo r minor modifications of permits (which do not require following the procedur es 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, plugg ing plan, post-injection site ca re 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 mon itoring to assist owne rs or operators and Directors in evaluating re quirements under §146.90. The guida nce can be found on EPA’s website at http://water.epa.gov/type/groundwater/u ic/wells_sequestration.cfm. In addition, in January 2009, DOE published a best practices ma nual entitled "Monitoring, Verification, and Accounting of CO2 Stored in Deep Geol ogic 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-inj ection site care and site closure plan.

EPA also believes that it is appropriate to re quire owners and operators to submit all plans, including the injection well pluggin g and post-injection site care a nd site closure plans, at the time of permit application. EPA belie ves that the Director needs a satisfactory level of assurance that the owner or operator has pl anned for these events before injection commences and that the owner or operator has ensured that appropriate financial reso urces 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 Federa l Register Cite: 146.91

187EPA Preamble Question: 35. EPA seeks comm ent on the frequency of all proposed reporting requirements. EPA Notice 43517

CSC Response: Frequency should reflect the level of risk asso ciated with the activity. Semi-annual reporting is adequate. Reporting s hould be on a project basis as opposed to a well basi s consistent with 146.23(c).

Individual Response: EPA is retaining the semi-annual repo rting requirements as proposed at §146.91(a). These requirements ensure the Direct or 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 fi nal approach to reporting and recordkeeping.

EPA disagrees that reporting shoul d 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 repo rting on all wells in a GS project at the same time; however, data for each well must be report ed separately and at least as frequently as required at §146.91.

EPA is using an adaptive approach to regula ting GS. The Agency plan s to, every six years, collect and review data on GS projects to dete rmine 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 Federa l Register Cite: 146.91(c) EPA Preamble Question: 36. EPA seeks comm ent on the requiremen t for electronic reporting in its proposed rule. EPA Notice 43518.

CSC Response: Industry’s objections to prior proposals for el ectronic reporting have been with the scope and breadth of information (incremental over written reports) that the Agency has previo usly proposed. Elect ronic reporting equivalent to existing written reports w ould 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 re quires this at §146.91(e).

EPA is developing guidance for states that describes the recordkeeping, reporting, and additional data management needs associated with GS act ivities and provides recommended guidelines on the types of data to be collected for tracki ng GS projects, reporti ng to EPA for compliance

188tracking, 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 a nnual reports (seeking comment)

Comment: Rule Provisions or Federal Register Cite: 73 FR 43518 EPA Preamble Question: 37. In addition to the above recordk eeping and reporting requirements, EPA considered a requirement for owners or operators of GS sites to provide an annual report during the lifetime of the proj ect, including the post-injection period, regarding the GS operation. Although EPA has not included a requirement for this report in its pr oposal, EPA seeks comment regarding the necessity for such an annual report. EPA Notice 43518.

CSC Response: An additional annual repor t is not necessary given the other reporting requirements in the Rule. Alterna tively, if this report was to replace the other reporting requirements, ther e 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 annua l report. Instead, EPA believes that periodic reevaluation of the AoR, as re quired at §146.84(e), along with any re visions 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 oper ators to review and update the AoR and corrective action plan, the testi ng and monitoring plan, and the emergency and remedial response plan throughout the life of the project. Owners or operators mu st review each plan and identify necessary amendments to the plan or demonstrat e 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 additi on of monitoring or injection wells), or when required by the Director. In no cas e can reviews occur less often than once every five years. For additional information, please see the final rule an d the preamble for a discussion of EPA's final approach to recordk eeping 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-annua l report in conjunction with the continued dialogue associated with AoR r eevaluations 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)

189Comment: Rule Provisions or Federal Regi ster Cite: 73 FR 43519-20, 146.93(b) EPA Preamble Question: 38. EPA is propos ing using a combination of fixed timeframe and a performance standard as described above. EPA is tentatively proposing a post-injection site care (monitoring) pe riod of 50 years with

Director’s discretion to cha nge 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 m odified at the Dir ector’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 pr esumption that monitoring should continue for 50 years is unnecessary and counterproductiv e. 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 proj ect 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 pr oject poses no threat of endangerment to USDWs-plumes that are still moving may, nonetheless, remain contai ned. 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 pr oposal below provides specific guidance on what the operator must show.

We recommend the standard in the propos ed alternative language for section 146.93(b) because it sets forth detailed criteria, all of which must be satisfied, to demonstrate that the site doe s not pose an endangerment to USDWs. The specific criteria listed in our propos al will serve to pr ovide 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 obtaini ng site closure based upon particular site characteristics and is, therefore, reasonably applicable to any storage site as opposed to a standard based up on a fixed-duration. Furthermore, it is more stringent than a purely discretiona ry approach because it establishes specific criteria that must be shown before site clos ure may be granted. We believe this language, which is an extens ion of work done by the World Resources

Institute and the Ground Water Protection C ouncil, avoids the noted shortcomings and provides stronger protection for USDWs.

This is the same recommendation as pr esented by the multi-stakeholder group, in which the Carbon Sequestrati on Council participated

Individual Response: EPA disagrees with the suggested changes. As noted above, EPA disagrees that a post-inj ection site care timeframe of 50 year s is excessive for most Class VI

wells.

190EPA 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 pos t-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 ensu res non-endangerment of USDWs pursuant to requirements at §146.93(c).

EPA believes however, that to ensure USDW protection from enda ngerment, a default timeframe for post-injection site care will be necessary in al l but a limited number of cases. This default 50 year post-injection site care ti meframe represents a reasonable and protective monitoring period based on a review of research studies, industr y reports, and existing environmental programs, and evaluation of public comments.

EPA believes that a default post-injection site car e 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 ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-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 propo sed well plugging plans a nd 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, demonstr ate the appropriateness ofan 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/groundwat er/uic/wells_se questration.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 Federa l Register Cite: 146.93 EPA Preamble Question: 39. EPA is re questing comments on the proposed requirements for well plugging, post-injecti on 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

191periods.

Individual Response: As described above, EPA acknowledges that there will be circumstances

where it can be demonstrated in less than 50 years that the plum e and pressure front no longer pose a risk of endangerment to USDWs. For th is reason, the final GS regulation includes a provision that the Director may, at his/her discretion, shorten th e post-injection site care time frame if the owner or operator can demonstrat e that the GS project does not pose a risk to USDWs, as specified in §146.93(b)(2). Alternativel y, the final rule at §146.93(c), also allows the Director to approve an alterna tive post-injection site care timefra me 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 ensu res non-endangerment of

USDWs. The demonstration must be based on site -specific information, in cluding the results of site-specific computational modeling; the predicte d timeframe for pressure decline; the predicted rate of carbon dioxide plume migration; site-s pecific chemical processes that will result in carbon dioxide trapping; the predic ted rate of carbon dioxide trap ping; characteri zation of the confining zone(s); laboratory analyses or stud ies to verify the information on trapping; the presence of potential conduits for fluid move ment and the quality of abandoned well plugs within the AoR; the distance be tween the injection zone and th e USDWs above and/or below the injection zone; and any additi onal site-specific factors dete rmined by the Director. The

demonstration must meet the cr iteria at §146.93(c)(2) for ensuring the quality and accuracy of

the data and models on which the demonstrat ion 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 require d at §146.82(a)(17).

EPA believes that a default post-injection site car e 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 ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-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 propo sed well plugging plans a nd post-injection site care and site closure plans required u nder §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, demonstr ate the appropriateness ofan 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/groundwat er/uic/wells_se questration.cfm.

Letter ID: 0190 Comment ID: 24549 Letter Lines: 4062 to 4069

Comment Code: 5260 2.8.2.3 Adjusting the post-injecti on timeframe (seeking comment)

192Comment: Rule Provisions or Federal Register Cite: 146.93(b)(2) EPA Preamble Question: 40. In additi on, EPA seeks comment on whether the

Director should be allowed to shorte n the timeframe based on performance information, and whether EPA should require a shorter or longer post injection period if data suggests the time fram e 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 plum e 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-injecti on 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 demons trate, during the permitting process based on substantial data, that an alternative PISC tim eframe may be appropria te 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 propo sed well plugging plans a nd 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, demonstr ate the appropriateness ofan 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 financia l responsibility requirements (40 CFR 146.85)

Comment: Rule Provisions or Federa l Register Cite: 144.36 EPA Preamble Question: 41. Current UIC guida nce describes trust funds as a form of financial assurance. The owner or ope rator 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 th e possibility that the owner or operator may face financial di stress prior to the trust being fully funded, EPA is considering a guidance appr oach that would recommend adopting a pay in period of three years for GS pr ojects, consistent with other similar programs in the Agency. EPA Notice 43521.

193CSC Response: Industry should have a vari ety of options for meeting financial assurance based upon the companies’ disc retion. Options should include selfinsurance, insurance, surety bonds or ot her appropriate financial instruments.

Individual Response: Owners or operators have the flexib ility to choose from a variety of

financial instruments to meet their financial re sponsibility obligations. Ow ners or operators may use one or multiple financial responsibil ity 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-injec tion site care period rather than with the permit application). A demonstration of financial responsibility for all ph ases of the GS project will be required prior to the issuance of a Class VI pe rmit (§146.85(a)(5)(i)). The qualifying methods are listed in §146.85(a).

Owners or operators may select different instru ments 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 fina l rule and preamble for further discussion of EPA's final appr oach 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 re gulations for Class I hazardous waste injection allow for the use of insurance for purposes of demons trating financial responsibility. However, insurance was not included as part of the guidance provided for Class II injection because th is insurance mechanism was and still is, rarely used for the purpose of de monstrating financia l assurance for injection wells. EPA is assessing whethe r 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 th e Director determines that the operator's proposed financ ial responsibility demonstration is adequate to protect USDWs from endangerment, which means the ability of th e owner or operator to pay for each activity for

194which financial responsibility must be demonstr ated, including correctiv e action on wells in the AoR, injection well plugging, PISC and site cl osure, 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 instru ments. See the final rule and pr eamble 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 asse ssing whether a financial ratings threshold for all companies using a self- guarantee, similar to those used by other Federal agencies, is appropriate. Th e Agency also is considering what constitutes an appropriate financial ra ting 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 opera tors may choose from a variety of financial instruments listed in §146.85(a) to m eet their financial responsibility obligations, provided the Director determines that the operator's proposed financial responsibility demonstration is adequate to pay for each activ ity for which financial responsibility must be demonstrated, including correctiv e action on wells in the AoR, in jection well plugging, PISC and site closure, and emergenc y 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 Federa l Register Cite: 146.85 EPA Preamble Question: 44. EPA is reque sting comments on whether financial responsibility mechanisms to be recommended in EPA gui dance should be adjusted in the manner described, whether additional instruments should be included, and whether other adjustments to the financia l responsibility mechanisms should be considered, all subject to EPA’s aut hority under the SDWA. EPA Notice 43522.

CSC Response: See response to Question 41 above.

Individual Response: As described above, owners or opera tors may choose from a variety of financial instruments listed in §146.85(a) to m eet their financial responsibility obligations, provided the Director determines that the operator's proposed financial responsibility

195demonstration is adequate to pay for each activ ity for which financial responsibility must be demonstrated, including correctiv e action on wells in the AoR, in jection well plugging, PISC and site closure, and emergenc y 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 si te care (seeking comment)

Comment: Rule Provisions or Federal Register Cite: 73 FR 43522 EPA Preamble Question: 45. The Agency is also requesting co mment 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 sepa rate 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 avai lable 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 financ ial 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 even t that the owner or operator combines more than one instrument for a specific GS activity (e.g., we ll 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, a nd 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), re quires 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 pl an, the PISC and site closur e 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 ow ner or operator to provide an adjustment of the cost estimate if the Director determines that the original demonstration is no longer adequa te, 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

196developing estimates of the costs associated with various GS activities. EPA will also discuss how to evaluate the appropriateness of single and multiple b onding and phased release of bonds in the guidance. EPA will review the require ments under SMCRA as it develops the guidance and incorporate any relevant information. This gui dance 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 particip ation process (seeking comment)

Comment: Rule Provisions or Federal Register Cite: 73 FR 43522-23 EPA Preamble Question: 47. EPA also reque sts comment on ways to enhance the public participation process, including engaging communities in the site characterization process as soon as ca ndidate locations are identified. EPA

Notice 43523.

CSC Response: CSC does not believe that th e public participa tion process should

be extended to the site characterization stage of a GS project, particularly given that many sites might be characte rized in the process of winnowing down the portfolio of potential sites.

Individual Response: The Agency believes that public particip ation is an important part of the UIC permitting process and wants to ensure wi de access to decision-making processes and information on projects that may affect the pub lic. GS permitting authorities must follow the existing public participat ion 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 requ est 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 percei ve potential environmental, economic, or

health effects.

Furthermore, the Agency recognizes that the ini tial phases of site evalua tion and site selection may begin in advance of permit application s ubmission. The public may become aware of these activities and begin to have questions or conc erns 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 a void public misperceptions about the nature and safety of GS projects. This may also benef it 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

197Comment: Rule Provisions or Federal Register Cite: 73 FR 43523 EPA Preamble Question: 48. To gain au thority 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, monito ring, and recordkeeping requirements that well owners or operator s 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 ga in primacy as long as they meet the requirements of the UIC program for obtai ning and retaining primacy. EPA should ensure that adequate funding is pr ovided 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 Territori es 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 we lls as well as have the necessary legal authorities to take administrative, civil, and criminal enfor cement actions required by the SDWA under §1423; impose criminal, civil, and administrative pena lties on owners and operators for non-compliance with regulatory requirements; and demonstrate sufficient/appropriate t echnical capacity (e.g., personnel, infrastructure, and technical expert ise) to implement their Class VI program.

EPA acknowledges that there may be technical and administrative challenges including resource concerns, and will work closely w ith the states to assist them in resolving funding issues or acquiring the resources, personnel, and traini ng 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 th at 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 ar e 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 Regi ster 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 seeki ng comment on the merits and possible

198disadvantages of allowing primacy approva l 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 determin ations. The final rule should also preserve state authority to determine what agencies will exercise primacy. Moreover, EPA should provide ad equate funding, which will require a substantial increase above current funding levels both to meet existing program needs and to provide the additional resour ces 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 a dvance 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 inde pendently 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 Fe deral requirements for Class VI wells as required under section 1422 of SD WA. Some states administer th eir 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 St ate, and the Oklahoma Department of Environmental Quality oversees other well classe s). 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., th e 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, a nd recognizes the existing expert ise 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 w ith the states to assist them in resolving funding issues or acquiring the resources, personnel, and traini ng 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 th at 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 ar e required to meet a minimum of 25 percent matching requirement.

199Letter ID: 0190 Comment ID: 24559 Letter Lines: 4138 to 4150

Comment Code: 5520 2.10.1 Appropriateness of existing p ublic 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 gather ing information. Such tools include cable networks, the Internet, and ot her 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 progr ams. 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 appropria te for GS projects. In addition, because of the unique nature of GS projects, and the anticipa ted level of public intere st in GS projects, EPA encourages early public involvement in GS proj ects. Providing the public with accurate, projectspecific information in the early stages of each GS project can help clar ify project details and avoid public misperceptions about the nature and sa fety of GS projects, a nd 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 participa tion 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 durati on of Class VI permits (seeking comment)

Comment: Rule Provisions or Federa l Register Cite: 144.36(a) EPA Preamble Question: 50. EPA proposes th at Class VI injection well permits would be issued for the operating life of the GS project including the postinjection site care period. EPA seeks comm ent 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 woul d yield administrative burden without commensurate benefits. The development of AoR, plans, and other parts of the

200permitting process must be addressed on a project-wide basis. Therefore it is important for permits to last for the oper ating life. It is al so sensible to allow for area permits.

Individual Response: EPA agrees with commenters that Cl ass VI permits should be issued for the operating life of the GS proj ect. 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 th e 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 operato rs’ iterative reevaluation of the project. Specifically, the final rule includes a requirement that the AoR be reev aluated 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 reme dial response plan th roughout 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 Ao R and corrective action plan, the testing and monitoring plan, and the emergency and remedial re sponse 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 we lls. 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 administ rative benefits offered by area permits can be achieved through well executed plans required for Class VI wells. EPA en visions that planned additional GS wells should be discussed as pa rt 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 injecti on and resultant pressure changes in evaluating the plan and setting pe rmit conditions. Similarly, testing and monitoring plans should account for future injection wells to ensure that ground water monitoring or CO2 plume and pressure front tracki ng 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 en sure 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).

201Letter 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 estimati ng 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 repr esent a significant component of the Cost Analysis, the Agency acknowledges that this factor may be significant in the overall uncertainty of the Cost Anal ysis. 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 characteristic s 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 experien ce in the UIC program and, hence, unsupportable. For many sites, monitoring wells should be unnecessary.

Individual Response: EPA recognizes that the number of m onitoring 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 descri bed the number of monitori ng 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. Therefor e, the number of monitori ng wells was indirectly based on the size of the AoR. Because ER projec t 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 si te compared to a saline formation project. EPA retained this assumption regarding the density of injection wells fo r the final rule analysis, but it changed its assumption on the number of monitori ng wells at each site. For the final rule, the Agency assumes one monitoring well above the inj ection 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 th e 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 sensitiv ity 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 a nnualized incremental rule costs approximately 16 percent less and 16 percent greate r than costs estimated for the primary analysis (as shown in

202Exhibit 5.26 of the Cost Analysis).

In response to the comment that monitoring well s will not be necessary for some GS projects, EPA clarifies that §146.90(d) re quires 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 n ecessitate the use of monitoring wells. EPA adds that projects operating under injection dept h 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 requireme nts, please see the fina l rule and preamble.

Letter ID: 0190 Comment ID: 24562 Letter Lines: 4227 to 4236

Comment Code: 7700 4.7 Executive Order 13045: Child ren'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 asse ss 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 anythi ng 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 Agen cy 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 Availabi lity (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 na tive mineral species that could potentially be mobilized by the intrusion of CO 2 and the potential ground water con centrations that could result to determine the potential for drinking water standards to be exceeded. EPA has also examined potential methods for conducting treatment of wa ter 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 invest igate the fate of dissolved CO2 in underground geologic formations and to determine possible ri sks associated with the dissolution of CO2 in

203underground aquifers. This STAR Grant is among six such grants awarded to major universities and institutions focusing on: "Integrated De sign, 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 protec t USDWs from endangerment through permitting, siting, construction, operation, injection, a nd 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 risk s to all populations, including ch ildren. The "Risk and Occurrence Document for the Geologic Sequestration Rule making," available in the rulemaking docket, presents a broad discussion of risks to human h ealth 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 approac h, EPA plans to collect and review available information, such as the research described above, and data every six year s on early GS projects, including impacts to USDWs and dr inking water quality that may aff ect the health of children, to determine whether the appropriate amount and t ypes of information and documentation are being collected, and to determine if modifications to the requirements are a ppropriate or necessary.

Letter ID: 0190 Comment ID: 24973 Letter Lines: 2566 to 2570

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 fina l 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 Federa l 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 op posite a cemented interval. EPA Notice

43509.

CSCopposes the requirement for cementing the long string casing back to surface.

204205 Cementing requirements should focus on ensu ring competent isolation and seal across the injection zone a nd confining zone(s). Seali ng 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 cem enting 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 an d 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 additi onal 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/gr oundwater/uic/wells_se questration.cfm.