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.1 Comments of Shell Exploration and Production Company

to the United States Environmental Protection Agency

on Development of Underground Injection Control Regulations for Geologic Storage of Carbon Dioxide

December 23, 2008

I. Introduction

A. Shell Exploration & Production Company (SEPCo) appreci ates this opportunity to provide comment to the Environmental Protection Agency (EPA) on it s proposed rule regarding Federal Requirements Under the Underground Injection Control ( UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells.

B. SEPCo strongly supports EPA’s effort to develop appropr iate regulations governing CO2 injection for purposes of GS. SEPCo agrees that GS is an impo rtant option for the reduction of CO2 emissions, that the UIC program provides an ap propriate framework for the regulation of CO2 injection, and that UIC regulations spe cifically tailored to CO2 injection could play a vital role in facilitating the develo pment and implementation of GS projects while ensuring that appropriate environmental s afeguards are in place.

C. As EPA has correctly recognized, it is critical that any UI C program regulation addressing GS be designed to achieve two goals. First, such a rule should ens ure that CO2 injection is conducted in a manner that is protective of human health and the e nvironment. Second, such a rule should effectively facilitate and encourage GS as a means to address climate change through the reduction of CO2 emissions to the atmosphe re.

D. Fortunately, there is abundant evidence that CO2 injectio n can be accomplished in a manner that is protective of human health and the environment. Indeed t here has been a long history of successful injection well operation in the Uni ted 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 lik ely to be large in scale, it is important to recognize that the injection of CO2 is nothing new. To the contrary, CO2 has been injected for purposes of enhanced oil and gas recovery (EOR /EGR) for more than thirty-five years, and the UIC program already regulates mor e than ten thousand CO2 injection wells that have successfully injected more than half a billion tons of CO2. We therefore have a vast body of experience demonstrating that CO2 injection can be conducted without adverse impacts on human health and the envi ronment.2

E. To achieve its goals for this rulemaking – to address the risk s of CO2 injection and promote

the use of GS to reduce CO2 emissions – we ask that EPA utilize mo re of the successful practices from the experience detailed above in its final decis ion on each of the requirements it has proposed for CO2 injection. SEPCo believes, as further detailed in these comments that the proposed requirements should be streamlined signific antly to increase the flexibility of the requirements for CO2 injection and reduce the unnecessa ry regulatory burdens the proposed rule would impose. SEPCo respectfully recommends EP A modify its proposed regulatory approach accordingly.

II. Specific Recommendations on the Proposed Regulations

a. Executive Summary

The primary areas of comment and a brief recommendation for each area are li sted

below.

• Lowermost USDW:

• Injection above the lowest USDW should be allowed but the operator should be required to demonstrate confinement above and below the injection

formation.

• Area of Review Reevaluation:

• The need for reevaluation of the AOR should be required – if at all – when there is site-specific evidence that there is actually a nee d to reevaluate the AOR. Where monitoring results remain consistent with modeling res ults, a requirement to reevaluate the AOR should not be required.

• Well Construction Standards:

• The Class VI requirements addressing issues such as well constr uction and mechanical integrity testing should be no different than the Class II requirement s.

• The choice of casing and cement materials should be selected ba sed on planned operating life of the injection well, not the ultimate duration of t he GS program. The potential for longer-term exposure of well components after inj ection has ceased will depend upon – and can be mitigated by – measures impleme nted at

closure.

• Site Characterization/Evaluation:3  EPA should seek to develop clear performance standards as detailed i n the American Petroleum Institute’s submission regarding site char acterization. The need for adequate site characterization and evaluation cannot be understated, however it is critical that EPA works to clarify the site evaluation needs and ensure that they are no more elaborate than necessary to ensure protection of USDWs.

• Closure and Post-Injection Site Care:

 Criteria for determining the period for post-injection site care should be performance-based and a function of the site-specific character istics of a project such as project size, geologic factors, and relative ris k of the project. (API offers such criteria in their edits to §146.93(b)(3).) Clear guidelines also need to be established regarding when operators have met the performance standards that determine site closure. Specific ally, the standard that the project no longer poses an endangerment to USDWs needs to be defined using reasonable risk-based criteria.

• Financial Assurance Provisions:

 EPA should keep language in the rule that allows for flexibility in the operator’s ability to utilize an array of financial assurance tools.

• Relationships with other Environmental Laws:

• EPA should clarify that gas-phase CO2 is not solid or hazardous wast e for RCRA purposes and is not subject to any RCRA waste determination requirements.

• EPA should clarify that supercritical CO2 is not solid or hazardous waste for RCRA purposes and is not subject to any RCRA waste determination requirements.

• In order to more clearly illustrate the actual risks of CO2 t ransport and storage, EPA should work to dispel concerns that geologic sequestration could be encumbered with those requirements except possibly through the comming ling of a captured CO 2 stream with an actual waste stream.

III. General Comments

A. SEPCo Supports Development of Appropriate UIC Progra m Regulations for

GS

.

SEPCo strongly supports the conclusion that the UIC progra m provides the appropriate framework for regulation of CO2 injection for GS. The UIC program gove rns a very wide range of underground injection activities – including the operation of t ens of thousands of existing CO2 injection wells – and enjoys an enviable and extensively docume nted record of success. The4

program has in many respects been a model for Federal-State co operation, and has benefited from a long history of regulatory and technical discourse among agen cies and regulators armed with considerable practical experience and exceptional technic al 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 measure s the UIC program relies upon to protect USDWs – measures designed to ensure that injected materi al 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 are bein g successfully applied to CO2 injection. Nevertheless, SEPCo agrees with EPA in the nee d to develop regulations more specifically designed to address CO2 injection in the GS conte xt. Our primary recommendation is that such regulations build on relevant UIC program experien ce, including experience with CO2 injection, and should be tailored to address the particular needs f or this category of injection activity: both the need to protect USDWs and the need to facilitate use of GS as a technology for reducing CO2 emissions. In developing such regulations, it is importa nt that EPA maintain a flexible, performance-based approach that allows regulators to tailo r specific permit requirements as appropriate based on the broad range of injection sites and pra ctices that may be encountered in the GS context and on the body of knowledge and experience that will be gained not only from pilot and demonstration projects, but from the initial deployment o f commercial scale GS projects.

B. SEPCo Supports Continued Application of the Class II Regulations to CO2 Injection in the Enhanced Oil or Gas Recovery Context and the C reation of “Class VI” Regulations to Address Other CO2 Injection We lls Used for GS

.

CO2 injection wells are currently permitted as Class II or Cl ass V “experimental technology” wells. Under the proposed rule, Class II CO2 injection would remain un der Class II, and a new classification – Class VI – would be created for GS. This appro ach makes sense. CO2 injection for purposes of enhanced oil or gas recovery (“EOR/EGR”) has been successfully regulated as Class II injection for decades, and there is nothing to justify any disr uption of the existing regulatory regime for the thousands of injection wells already in use in these o perations. For other GS injection projects, Class VI regulations would permit a more structu red basis for regulation than the Class V regulations.

C. The Proposed Class VI Requirements Are Far More Burd ensome than Necessary

to Protect USDWs.

As the preamble acknowledges, the actual human health and ecol ogical risks associated with GS are relatively remote and can be addressed effectively through me asures implemented to protect USDWs. 73 Fed. Reg. at 43497-98. Unfortunately, the propos ed rule seems to proceed from the premise that the strictest UIC regulations in existence – th ose for hazardous waste injection – should serve as the starting point for the development of the Class VI regulations. Given the vast knowledge and experience developed through the handling of CO2 i n different operations, SEPCo contends that the more logical starting point for development of the Class VI regulations is the Class II regulations.5

As the proposed rule recognizes, CO2 injection operations ha ve been conducted pursuant to the Class II regulations for many years, and experience with tho usands of wells injecting hundreds of millions of tons of CO2 demonstrates that the Class II regulat ions – as applied to CO2 injection – are adequate to protect USDWs This is certainly true with re spect to the basic construction, operating, monitoring, and mechanical integrity testing re quirements for injection wells; we believe that what “works” in terms of the construction and operatio n of a CO2 injection well does not depend on the purpose for which CO2 is being injected.

Unfortunately, the proposed Class VI requirements are far m ore stringent than the Class II requirements, a fact that gives rise – under the proposed rule – to the need to “grandfather” Class II CO2 injection wells that remain in service for GS purposes a fter oil or gas production has ceased. Rather than resembling the Class II requirements, the propo sed Class VI requirements are as stringent as those for hazardous waste injection in most res pects. Indeed, many of the construction, mechanical integrity, and monitoring and financial assura nce requirements proposed for Class VI wells are even more comprehensive and stricter than those for hazardous waste injection wells. While some of these more burdensome requirements are legitim ately related to concerns about the mobility of CO2 or the anticipated scale of GS operations, man y – as discussed in Part III of these

comments – are not.

Recommendation:

The Class VI requirements addressing issues such as well con struction and mechanical integrity testing should be no different than the Class II requirements.

D. Rules that Stigmatize GS or Burden it Excessively Would N ot be in the Public

Interest

.

The magnitude of the regulatory burdens imposed by the proposed C lass VI requirements is of concern for several reasons. First, unnecessary regulator y burdens would act as a direct impediment and disincentive to the development of GS projects. Less directl y, the imposition of unreasonably stringent regulatory requirements – particularly requirem ents for multiple layers of protections addressing the same basic risk – inherently magnify the impress ion of risk and could thus stigmatize GS and deter investment in GS projects.

SEPCo understands the importance of public perception when i t comes to the siting and permitting of needed infrastructure, and believes strongly in the need to en sure that the public has accurate information to inform it. To facilitate the public’s appre ciation of the merits of GS, SEPCo urges

EPA to ensure that it does not overstate the risks associated w ith CO2 injection or understate the justified confidence with which many potential issues and co ncerns can be addressed Similarly, SEPCo urges EPA to avoid the imposition of regulatory require ments that are so disproportionate to the risks involved that they may do more to amplify than address public concerns. To this end, EPA should scale back its regulatory requirements to more ac curately reflect the magnitude of actual risks and to ensure that the requirements imposed are necessar y for the protection of USDWs.

SEPCo believes that permanent storage of CO2 can be accompl ished safely and without harm to the environment by utilizing the appropriate knowledge base, de tailed site-specific information,6

technical expertise, and sound management practices. It is t herefore 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 deter s use of this key technology for reduction of CO2 emissions to the atmosphere.

Recommendations:

EPA should consider that overly-burdensome regulation – to the extent it effectively impedes or deters use of a “promising technology” for the reduct ion of greenhouse gas emissions – could prove environmentally counterproductive, given potential oper ators inability to deploy GS projects.

E. Lowermost USDW Restriction

The proposed rule limits Class VI injection to injection in to formations that are below the lowermost underground source of drinking water (USDW). This requirement is not necessary for the protection of USDWs and would remove a vast number of via ble formations 1/ from consideration for GS. Industry has shown that it can operate CO 2 injection wells in an EOR/EGR context without endangering USDWs that are located below the injection zone. An excellent example is the Salt Creek EOR project in Wyoming, which ha s a USDW below the injection zone. Moreover, under the proposed rule, there are other measures th at would provide real assurance of formation integrity and require operators to demonstrate tha t their project will not endanger USDWs, making the lowermost USDW restriction unnecessary.

Recommendation:

Injection above the lowest USDW should be allowed but the opera tor must demonstrate confinement above and below the injection formation.

F. 50-year Default Post-Injection Site Care

SEPCO objects to the use of a 50-year default monitoring perio d. EPA offers no rationale for this arbitrarily selected period of 50 years and establishing a fix ed and unusually long time period may create a significant barrier for operators considering entr y into CCS operations.

Recommendation:

Criteria for determining the period for post-injection site care should be performance-based and a function of the site-specific characteristics of a project such as project size, geologic factors, and relative risk of the project. (API offers such criteria in th eir edits to §146.93(b)(3).) Clear guidelines also need to be established regarding when operators have met t he performance standards that

1/ Referring to the Weyburn project, EPA has noted, “ The conclusions of Phase I of the project are that depleted

oil and gas reservoirs from EOR operations are a pr omising CO2 storage option . . ..” 73 Fed. Reg at 4 3500.7

determine site closure. Specifically, the standard that the pr oject no longer poses an endangerment to USDWs needs to be defined using reasonable risk-based criteri a.

G. RCRA

SEPCO agrees with the concept that Class VI wells should n ot be injecting hazardous wastes but is proposing some modifications to EPA’s definition of CO2 strea m 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 origin al text would have precluded injection of CO2 from some sources. SEPCo contends that the question of ho w CO2 should be accounted for in a GHG management and accounting system is beyond the scope of this regulation. More to the issue of “impurities”, SEPCO objects to any mandated purity s tandards for CO2. The inclusion of impurities in stored CO2 should not be arbitrarily prohibite d; however, it is recognized that the presence of those impurities at sufficient concentrations may trigger the applicability of other statutory limits or requirements. Determining the type an d levels of impurities in the CO2 stream is – absent a compelling public or environmental health risk – bes t left to contractual negotiations between partners in a CCS value chain as opposed to an arbitra ry regulatory determination. The contracting parties are best able to evaluate the types of im purities, their compatibility with the reservoir and equipment, and determine the acceptable levels o f those impurities in the stored CO2. To the extent that there is an overriding public interest in li miting the type or level of contaminants, principles of cost-effectiveness and risk-management shou ld guide the decision making process.

With specific respect to RCRA, SEPCo is concerned that EPA’s b rief discussion of a supposed potential for injected CO

2 streams to be characterized as hazardous waste (or some type o f hazardous release) could have a significant chilling effect on the deployment of CO

2 capture and sequestration technologies. Based on the work of our engine ers and scientists with capture technologies and their extensive experience 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 RCRA. In addition, EPA’s Proposal suggests tha t injected CO

2 may be considered hazardous waste for RCRA purposes, and defines “carbon dioxide s tream” to exclude hazardous waste. 73 Fed. Reg. at 43503. The premise appears to be that C O 2 is solid waste, and that a waste determination for such solid waste would turn on the specific composition of the CO 2 in question. Id. Based on this premise, the preamble suggests, “EPA cannot m ake a categorical determination as to whether injected CO

2 is hazardous waste under RCRA.” Id.

Rationale:

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 po sition that gasses do not qualify as “solid waste” under this definition unless they are “containe d” in a cylinder or similar container. 54 Fed. Reg. 50968 at 50970, 50973 (December 11, 1989). It follo ws that gas-phase CO 2 streams are not solid waste, are not subject to the waste determination r equirements of 40 C.F.R. 262.11, and cannot be considered hazardous waste for RCRA purposes.8

The RCRA definition of solid waste is limited to “solid, liquid, s emi-solid, or contained gaseous material.” RCRA 1004(27). Because supercritical CO 2 is none of these things; a plain reading of the statutory text suggests that supercritical CO 2 should not be considered “solid waste.” This reading of the statute makes sense, because RCRA is plainly aimed at the kind of material that could end up being dumped into a landfill. Uncontained supercritical CO

2 is not such a material. Instead, the physical properties of supercritical CO 2 are such that it would immediately vaporize – becoming an uncontained gas – before it could contribute to the contents of a landfill. A related practical

consideration is the fact that the hazardous characteristics – the broad waste determination criteria that provide a primary means for determining when solid waste is hazardous waste – are based largely on test methods that are inapplicable to materials su ch as supercritical CO 2 . In particular, the toxicity characteristic depends on test methods that can only b e applied to materials that are solids or liquids at standard temperatures and pressures. This is unsu rprising, because the toxicity characteristic was designed to assess the threat waste wo uld have in a municipal landfill disposal scenario, a scenario that – as already discussed – is inherently i napplicable to supercritical CO

2 . Accordingly, it makes no legal, policy, or practical sense t o treat uncontained supercritical CO

2 as “solid waste” for RCRA purposes. EPA should therefore confir m that uncontained supercritical

CO 2 is not “solid waste” and is not subject to RCRA waste determina tion requirements.

It follows that a CO 2 stream would only qualify as “solid waste” if it is actually in the form of a liquid (i.e., a liquid containing dissolved CO

2 ). In such a case, the liquid would meet the statutor y definition of “solid waste,” the requirement to perfo rm a RCRA waste determination would be triggered, and the familiar test methods for waste determinati ons could be applied.

Recommendations :

There are important categorical determinations that EPA can and should make with respect to the

RCRA status of CO 2 . SEPCo recommends the following:

1. EPA should clarify that gas-phase CO

2 is not solid or hazardous waste for RCRA purposes and is not subject to any RCRA waste determination requireme nts.

2. EPA should clarify that supercritical CO

2 is not solid or hazardous waste for RCRA purposes and is not subject to any RCRA waste determination r equirements.

3. In order to more clearly illustrate the actual risks of CO

2 transport and storage, EPA should work to dispel concerns that geologic sequestration could be e ncumbered with those requirements except possibly through the commingling of a c aptured CO

2 stream with an

actual waste stream.

IV. Comments Regarding Proposed Class VI Requirements

A. Geologic Siting Requirements

The preamble to the proposed rule outlines normal site select ion criteria for injection well projects, including the need to identify an injection zone with sufficie nt permeability, porosity, thickness and lateral extent and a low-permeability confining zone with sufficient thickness and lateral extent to9

protect overlying USDWs. 73 Fed. Reg. at 43505. These are fam iliar and appropriate requirements, and they appear to be appropriately embodied in the regulatory t ext proposed for codification at 40 C.F.R. 146.83(a). Unfortunately, the preamble goes on to s uggest the need for extraneous detail in the evaluation of site conditions. In addition, the rule text pr oposed for codification at 40 C.F.R. 146.83(b) would allow the Administrator apparently unlimi ted discretion to impose additional siting requirements that go beyond those necessary to ensure protec tion of USDWs.

Recommendation:

EPA should omit the latter requirement of extraneous details, and instead seek to deve lop clear performance standards as detailed in the American Petroleum Institute’ s submission regarding site characterization. The need for adequate site characterization cannot be understated, however it’s is critical that EPA works to clarify the site evaluation needs and ens ure that they are no more elaborate than necessary to ensure protection of USDWs.

1. Site Evaluation

The preamble appears to suggest that there may be a need for a n elaborate evaluation of site conditions to address concerns related to seismicity and potenti al geochemical interactions. In fact, however, seismicity and geochemical compatibility are is sues that are easily addressed in the GS context, and requirements for unnecessarily elaborate anal ysis would serve only to burden and impede the development of GS projects.

Concerns with respect to seismicity are frequently raised i n the injection well context, but there is ample experience demonstrating that such risks are modest a nd easily addressed through appropriate injection pressure limitations. Similarly, geologic comp atibility – while it can present issues in some contexts – is unlikely to present any serious problems in the G S context. These conclusions are confirmed by decades of experience with thousands of Class II C O2 injection wells injecting

hundreds of millions of tons of CO2.

While it is true that injection of CO2 can be expected to lead to t he formation of carbonic acid, the resulting carbonic acid is only weakly corrosive and – as exp erience 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 exp resses specific concern about geochemical reactions that could alter the composition of th e injected CO2 stream – particularly through the mobilization of contaminants that occur natura lly in the injection zone – but such concerns are immaterial because the specific composition o f the CO2 stream matters little as long as

the CO2 remains confined. Another theoretical concern rela tes to the potential for geochemical changes to contribute to the plugging of pore spaces in the in jection zone. However, experience with Class II CO2 injection confirms pore plugging should not pose any practical problems in the CO2 injection context because of the relative weakness of carbonic acid and the time and transport distance required for carbonic acid to form and for any subsequen t geochemical changes to occur. Even if pore plugging were to manifest it, it would occur deep in the injection zone where its effect would be minimal. In any event, the impact of pore plugging wo uld only be to decrease permeability in the injection zone, thereby reducing the eff iciency (but not the safety) of the injection operation.10

In short, geochemical changes related to CO

2 injection cannot be expected to be material to the protection of USDWs. Accordingly, there is no credible basis for the suggestion (73 Fed. Reg. at 43505) that “[s]tudies of rock samples and review of geochemic al data from monitoring wells are needed to evaluate the impact” of potential geochemical chang es related to CO

2 injection.

Recommendation:

Remove requirements for detailed analysis of potential chem ical or mineralogical reactions that are unnecessary to ensure protection of USDWs.

2. Redundant Confining/Containment Zone Requirement

EPA requests comment on whether the Final Rule should requir e, or allow the Administrator discretion to require, additional confining and containment z ones above the primary confining zone. 73 Fed. Reg. at 43505-06. SEPCo strongly opposes any such req uirement.

Rather than being necessary for the protection of USDWs, a re quirement for additional confining and containment zones above the injection zone would apply in addition to the requirement for an adequate demonstration that USDWs will be protected. By defin ition, such a requirement is unnecessary. Having demonstrated the adequacy of their belts , there is no need to require permit applicants to furnish suspenders as well.

It should also be noted that a requirement for additional confini ng and containment zones above the injection zone would be unprecedented. No such requirement ex ists in the UIC program, even in the context of hazardous waste injection. Nor does such a requ irement apply in any of the countries where GS projects are currently underway (including Norway, C anada, Australia and Algeria). EPA should not single out GS for heightened and substantially more r igorous requirements than would

be warranted on the merits of the actual risk.

Recommendation:

Require potential operators to demonstrate that USDW s will not be endangered by the proposed injection activity in the primary containment zone through the Class VI permitting process, without adding a requirement of any secondary confining or containment zones.

B. Area of Review and Corrective Action Requirements

We support the use of computational models for determination o f the appropriate area of review (“AOR”) for GS purposes. Modeling of the pressure effects ass ociated with injection – together with conservative modeling to bound the potential extent of CO 2 plume movement – are appropriate aids to the evaluation of geologic siting and corr ective action to address risks presented by penetrations such as abandoned boreholes. The use of such m odeling is already well established in the context of oil and gas exploration and production and has be en used in the UIC program for “no-migration” petitions for hazardous waste injection. S imilar modeling can reasonably be adopted

for use in the GS context as well.11 1. AOR Definition

The proposed rule vaguely defines the AOR as “the region sur rounding” the GS project that “may be impacted by the injection activity.” 72 Fed. Reg. at 43535 (p roposed 40 C.F.R. 146.81(d)). The definition goes on to suggest that the AOR is to be “based on com putation modeling that accounts for the physical and chemical properties of all phases of the i njected carbon dioxide stream.” Id.

There are two issues.

First, the proposed definition suggests the need for a more com plex modeling approach than may typically be necessary or appropriate. As experience wit h hazardous waste injection shows, it is rarely necessary to attempt to model chemical changes in the injectate plume. Indeed, it is typically far easier to model transport than chemical fate, and conserva tive modeling of transport should typically be sufficient by itself to show that USDWs will no t be endangered. Where this is the case, it is containment of the plume – rather than the precise compos ition of the plume – that matters, and modeling of chemical changes would be unnecessary. Simil arly, the preamble suggests that the ”most sophisticated” and most “accurate” modeling should be pr eferred or even required. 73 Fed. Reg. at 43507. Again, however, the appropriate goal is to ensure protection of USDWs, and simpler, more conservative modeling may often be sufficient (and even p referable) for this purpose.

Second, the functional purpose of the AOR is to define the area within which impacts of the injection activity could cause endangerment of a USDW; speci fically, the AOR defines the area within which corrective action for abandoned boreholes may b e necessary to prevent endangerment of USDWs. The language of the proposed rule (i.e., “may be imp acted by the injection activity”) is not clearly limited to impacts of the injection activity that could cause endangerment of USDW’s , and it

should be.

2. Corrective Action

Corrective action is a familiar UIC program requirement. Gi ven the potential scale of GS operations, EPA has proposed requirements for a corrective a ction plan contemplating periodic reassessment of the AOR and a phased implementation of corre ctive action. In general, this approach is prudent and practical, providing what will ultim ately be a rigorous approach to corrective action while reducing regulatory burdens by perm itting a phased implementation of corrective action requirements. However, SEPCo does not be lieve that a minimum frequency for reevaluation of the AOR should be required.

Recommendation:

The need for reevaluation of the AOR should be required – if at all – when there is site specific evidence that there is actually a need to reevaluate the AOR. Where monitoring results remain consistent with modeling results, a requirement to reevalu ate the AOR should not be required.

C. Injection Well Construction Requirements

1. Well Design12

Many years of experience with the Class II UIC program – inclu ding 35 years of CO2 injection in the EOR context – have demonstrated that the construction requ irements for Class II injection wells are sufficient to ensure that injected fluids cannot esc ape from the intended injection zone via the injection well borehole. The proposed rule would never theless impose substantially more costly well construction requirements resembling those for Class I hazardous waste injection wells. The proposed rule specifically cites the buoyancy of CO2 as the j ustification for these requirements. See 73 Fed. Reg. at 43509.

SEPCo argues that the buoyancy of CO2 in no way justifies t he additional construction requirements proposed. The reason for this is straightforw ard: by far the greatest driving force for fluid migration along an injection well borehole is the pres sure build-up (or “cone of influence”) caused by fluid injection during the operation of the injectio n well. The magnitude of this pressure influence is at its maximum at the point of injection, and – wit hin the injection interval – it generally falls off logarithmically with lateral distance from the in jection well borehole. At some distance from the injection well, the pressure influence of the inje ction activity can be expected to decline to the point where density-driven flow (i.e., buoyancy) could b ecome significant (at least in relative terms) as a driver for vertical fluid migration. At the injec tion well, however, the induced pressure gradient caused by the injection activity would so dwarf the im pact of buoyancy as to render the latter insignificant.

In short, buoyancy can be significant as a driver for lateral f luid movement, but provides a relatively weak driver for vertical fluid flow that – at the point of inject ion – is insignificant in comparison to the pressure gradients caused by injection. Accordingly, it would be unreasonable to suggest that buoyancy justifies significantly more demanding injection well construction requirements than have already proven to be sufficient in the case of Class II CO2 inje ction wells.

SEPCo nevertheless supports the requirements for a surfac e casing cemented to the surface, for injection through a tubing and packer, and for a well design th at permits continuous monitoring of a pressurized annulus. The requirement SEPCo finds objectio nable is that for continuous cement along the entire long-string casing. This requirement – wh ile appropriate for hazardous waste injection wells – is simply too costly to justify in the case o f CO 2 injection. Cement must of course be sufficient to prevent endangerment of USDWs, but the speci fic measures necessary to achieve this performance standard are heavily dependent on site-spec ific conditions and are most appropriately determined in the permitting process.

Recommendation:

Utilize Class II well construction standards for the Class V I program. The proposed design standard mandating continuous cement for the long string casin g should be deleted as unnecessary and unduly burdensome.

2. Materials of Construction

Besides specifying additional construction requirements, th e proposed rule would require the use of degradation-resistant construction materials such as acid-r esistant cement and a corrosion-resistant casing. 73 Fed. Reg. at 43510. These requirements are base d on the premise that CO

2 is corrosive13

and that experience with CO

2 injection in the EOR context suggests that corrosion is a sig nificant issue. 73 Fed. Reg. at 43509-10.

In fact, CO2 is not corrosive. What is corrosive is carbonic acid formed through the interaction of CO2 and water. This distinction is critical from a practical standpoint, because injected CO2 streams would often (if not generally) be “dry”(i.e., dehydr ated) and therefore non-corrosive. Once injected, the “dry” CO2 would come into contact with natural ly-occurring water in the subsurface, creating carbonic acid. However, an injection well would i nject CO2 far more rapidly than the CO2 could mix with water, creating a CO2 plume that would immedia tely displace water away from the point of injection, creating a plume of relatively pure CO2 s urrounding the point of injection. While CO2 would mix with water around the boundaries of this plume, the plume itself would continue to consist of relatively dry (and therefore non-corrosive) CO2. In this situation – which can be expected to be typical in the carbon sequestration context – th ere is no basis to suggest that injected CO2 is corrosive or that injection wells must be designed and co nstructed to resist a particularly

corrosive environment.

Class II experiences with CO2 injection supports this con clusion. Corrosion is an issue for injection wells used to produce “wet” streams containing oil, brine, and C O2 fractions brought up in the course of EOR/EGR operations (which may contain significant carbonic acid). However – and this is the point that is relevant to the GS context – “dry” CO2 inject ion systems have operated for many years without the need for corrosion-resistant const ruction or the occurrence of corrosionrelated problems.

Well construction requirements under the UIC program genera lly require that operational conditions and the nature of formation fluids and proposed injectate be con sidered in well construction, and these general requirements have served well. Thus, while there may be some Class VI CO2 injection scenarios in which corrosion-resistant materials may be r equired, there is no technical basis for any general presumption that they are necessary or should be requ ired.

Recommendation:

The choice of casing and cement materials should be selected ba sed on planned operating life of the injection well, not the ultimate duration of the GS program. The potential for longer-term exposure of well components after injection has ceased will depend upo n – and can be mitigated by – measures implemented at closure.

D. Injection Well Operating Requirements

1. Injection Pressure Limitations

Under the existing UIC regulations, permits for Clas s II injection wells must limit injection pressure

as follows:

Injection pressure at the wellhead shall not exceed a maximu m, which shall be calculated so as to assure that the pressure during injection do es not initiate new fractures or propagate existing fractures in the confining zone adjacent to the14

USDWs. In no case shall injection pressure cause the movemen t of injection or formation fluids into an underground source of drinking water.

40 C.F.R. 146.23(a)(1). This has proven to be an effective r egulatory requirement that provides a flexible and appropriate performance standard to be applied on the basis of site-specific conditions. This regulatory approach has proved successful in the Class I I context, and there is no basis to conclude that a similar standard would not be appropriate in th e context of carbon sequestration.

The Class I requirements impose more restrictive requireme nts designed not just to prevent endangerment of USDWs, but to ensure that there is no fracturi ng in the injection zone during normal operation. The latter requirement may make sense when “no migration” exemptions depend upon the integrity of confining or “arrestment” strata within the injection zone, but such a requirement is certainly more rigid than necessary to prevent endangerment of USDWs. Accordingly, such a standard is not necessary in the context of carbon sequestrati on, and would be ill-suited in a rule that must have the flexibility to address a wide range of potential injection scenarios.

Recommendation:

Injection pressure limitations for Class VI injection we lls should be based on the existing Class II requirements, modified slightly to address the possibility of C lass VI injection occurring above the lowermost USDW. We recommend the following specific langua ge:

Injection pressure at the wellhead shall not exceed a maximu m, which shall be calculated so as to assure that the pressure during injection do es not initiate new fractures or propagate existing fractures in the confining zone. In no case shall injection pressure cause movement of injection or formatio n fluids that endangers an underground source of drinking water.

2. Down-Hole Shut-Off Valves

EPA proposes to require automatic shut-off valves down hol e as well as at the surface. Such a requirement would be costly and is completely unprecedented in the UIC program. Down hole shut off valves would increase well construction and operation costs, and could significantly complicate well testing and workovers. Class I hazardous waste injecti on wells are not required to have downhole automatic shut-off valves, and there is no basis to sugg est that CO 2 injection entails higher risks warranting costly additional safety measures that would inte rfere with monitoring and potentially with any necessary well remediation.

3. Corrosion Monitoring

As already discussed, CO

2 is not corrosive in the absence of water and there is no basis t o assume that carbon sequestration wells will typically or even of ten be injecting corrosive fluids. A general requirement for corrosion monitoring is therefore unneces sary and inappropriate.

E. Mechanical Integrity Testing (MIT) Requirements15

The proposed rule suggests, “MIT requirements for GS wells s hould be tailored to address the unique properties of CO2, specifically its buoyancy and pot ential corrosivity.” 73 Fed. Reg. at 43513. As previously discussed, however, the buoyancy of CO2 is a relatively trivial factor in relation to the cone of influence created by injection pressu re during injection, a factor that makes buoyancy virtually irrelevant as a driving force for upward m igration through the injection well borehole during the operational life of a GS well. According ly, there is no basis to suggest that the buoyancy of CO2 is relevant to be considered in establishing m echanical integrity testing requirements for GS wells. Similarly – as also previously dis cussed – CO2 is not corrosive and cannot be expected to cause corrosion problems for the inject ion well (including down-hole cement) unless the CO2 stream itself contains water. Consequently , corrosion generally should not be expected to be a problem and concerns related to corrosion do no t justify any particularly stringent 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 f or CO2 injection in the EOR/EGR context, and there is no reason why they should not be sufficie nt in the GS context as well.

F. Testing and Monitoring Requirements

The preamble to the proposed rule indicates, “EPA considers CO 2 plume and associated pressure front monitoring to be necessary for verification of model p redictions.” 73 Fed. Reg. at 43514. This is difficult to understand because the regulatory regime f or Class I hazardous waste injection wells do not require elaborate modeling, and plume or pressure front monitoring have never been considered necessary and are not required in that context. In fa ct, extensive experience with Class I hazardous waste injection demonstrates that plume and press ure front monitoring is not necessary, either to provide confidence in modeling results or otherwise. By suggesting otherwise, the proposed rule unnecessarily undermines confidence in the mode ling demonstrations that can and should be relied upon to support determinations that injected CO 2 will not endanger USDWs.

The suggestion that it makes sense to monitor the movement o f injected CO2 in the subsurface also does not consider the nature and utility of modeling used to evalua te injection well projects and of

the technical difficulties and uncertainties such monitorin g would involve. The root of the problem relates to the fact that modeling provides a conservative asse ssment of the potential for movement of injected fluids in the subsurface, not a precise “prediction ” of actual fate and transport that can or should be “verified” on the basis of elaborate, costly, and unce rtain efforts to observe the actual movement of fluids in the subsurface. As experience with ha zardous waste injection shows, injection well operational data and the results of pressure fall-off tests provide ample data to validate the results of modeling. The additional monitoring requireme nts proposed in the GS context are excessive and unjustified.

Suggestions that it should be necessary to monitor geochemi cal changes or to study interactions between brine and CO2 in the injection zone are particularl y troubling, because detailed information concerning such interactions should rarely if ever be releva nt from a regulatory standpoint. In particular, USDWs are generally protected by ensuring that i njected fluids will remain isolated from them, and experience with hazardous waste injection – where the injection of highly corrosive waste is not uncommon – has shown that geochemical interactions tha t could actually compromise containment cannot reasonably be expected in the absence of truly unusual circumstances.16

Accordingly, any general requirement to monitor geochemic al changes in the subsurface would be

unreasonable.

1. Monitoring CO2 Movement and Reservoir Pressure

The preamble to the proposed rule specifically states that th e “[m]onitoring of subsurface geochemistry and the position of the CO2 plume and pressure fro nt are necessary to verify predictions of plume movement, provide inputs for modeling, i dentify needed corrective actions, and target geochemical and surface monitoring activities.” 7 3 Fed. Reg. at 43514. Again, this is an assertion that cannot be reconciled with experience with C lass I hazardous waste injection, where such monitoring has never been considered necessary and is not r equired.

a. Monitor Wells

Monitor wells reaching the deep subsurface are problematic in a variety of respects. They are expensive to install, create potential pathways for verti cal fluid migration, and – in the deep subsurface where natural fluid movement may be very slow or effectively non-existent – they have little potential to provide more than an isolated “point meas urement.” If the object is to track injected fluid within

an injection zone, a monitor well could be placed in the path of the waste front to detect the waste front when it goes by, but the exercise w ould amount to a very expensive way to generate a single data point. There would be less likelihood o f any benefit from monitoring wells designed to detect potential leakage from an injection zone, be cause the ability to detect such leakage is at best a hit-or-miss (if not a needle in a haystack) propo sition. Monitor wells also have built-in confounding factors that include both the potential for wel l construction to impact fluid quality in the target sampling interval and the fact that sampling may it self cause fluid movement that might not otherwise occur. Because pressure fronts extend much fur ther than injected fluid plume fronts during injection, pressure monitoring is more likely to be us eful than fluid sampling, but costs would still be very high and the ability to detect relevant changes would still be very much hit-or-miss. For these reasons, EPA chose not to impose monitor well require ments for Class I hazardous waste injection wells, though it did allow monitor wells to be requ ired at the discretion of the Administrator to address particular circumstances at the sit e. See 52 Fed. Reg. 32446 at 32463-64 (August 27, 1987), 53 Fed. Reg. 28118 at 28141, 28144-45 (July 26, 1988). Experience with hazardous waste injection does not commend the use of monitor wells even in that context, and there is no justification to impose as stringent an approach – let alone a more stringent approach – for the injection of CO2.

b. Geophysical Methods for Plume Tracking

As an alternative to monitor wells, the proposed rule sugges ts that it may be possible to use remote geophysical techniques for “plume tracking.” 73 Fed. Reg. a t 43515. Unfortunately, it is not clear that there are established technologies available that are sufficiently reliable and mature in their development for application in a regulatory context. In gene ral, the technologies available would be very expensive to employ on the scale required, and provide in ferential data that is subject to considerable interpretation. Such techniques are unsuitab le for required use in a regulatory context.17

The problem with interpretive tests is that they are interpretive and therefore inherently subject to uncertainties. The suggestion that such techniques could b e used for “plume tracking” to “verify” the results of modeling is optimistic at best, and creates unr ealistic expectations for the technologies involved. In fact, the use of such techniques may do more to am plify residual uncertainties and thereby undermine public confidence in GS.

2. Surface Air and Soil Gas Monitoring

The goal of any UIC program regulations for GS should be to ensu re that injected CO2 streams remain confined in the subsurface and do not endanger underground s ources of drinking water. EPA has proposed elaborate – and in many cases overly-elaborate – requirements to ensure that this goal is achieved. Consequently, it is difficult to imagine how requirements for surface air or soil gas monitoring could be justified.

As EPA seems to recognize, surface air or soil gas monitoring would impose substantial costs and the results of such monitoring would be subject to a host of c onfounding factors. Worst of all, such monitoring would be aimed at leakage of CO2 all the way to the surface, which – in the case of any properly-permitted GS project – would by definition be an extr aordinarily low probability scenario.

Recommendation:

Surface Air and Soil Gas Monitoring should not be imposed, nor should regulators have discretion to impose them. The potential for possible leakage pathwa ys should be demonstrated and managed during the permitting process.

G. Post-Injection Site Care Responsibility

The proposed rule contemplates a long post-operational peri od of observation and “site care” prior to closure. The requirements contemplated – including a pres umptive 50-year post-injection monitoring period – are unwarranted and completely unprecedente d in the UIC program. Not even hazardous waste injection wells – which generally operate subject to a demonstration that waste will be contained for at least ten thousand years – are subject to such burdensome post-injection requirements.

Long term protection of USDWs is ensured up-front, primaril y through proper siting as confirmed through the technical evaluation that occurs in the permit ting process. Proper well construction, operating, monitoring and testing provide assurance agains t problems during the operational life of an injection well, but siting doesn’t change, and proper sit ing must be ensured at the start. Once injection operations cease, there should generally be no ne ed to do more than monitor pressure decay in the injection zone and ensure proper plugging of the injection well. This approach is sufficient for the injection of hazardous waste, and it certa inly should be sufficient for the injection of CO2. The premise that careful siting and AOR evaluation a re not enough – that actual monitoring for decades after the cessation of injection is nee ded – is foreign to the UIC program and inconsistent with the long and thoroughly-documented succ ess of UIC regulation in the United

States.18

There is certainly no justification for a presumptive 50-ye ar minimum timeframe for post-injection site care, and such a requirement would likely kill-off comme rcial investment in geo-sequestration projects. It does not help that the proposed rule provides a mec hanism for shortening the presumptive 50-year requirement, because the ability to s horten the post-injection site care period would depend on the apparently unlimited discretion of the Direc tor and could not be assessed in any meaningful way before injection operations near compl etion. Moreover, the possibility of a shorter post-injection site care period is balanced by the pos sibility that the Director may seek to impose an even longer post-injection site care period. The b urdens and regulatory uncertainties of an extended post-injection site care requirement cannot be ju stified, especially in the context of a regulatory program that requires a “non-endangerment” demon stration before injection can even

commence.

Recommendation:

1. EPA should operate from the premise that the UIC program is preventive in nature.

2. Release from post-injection site care should be determine d not by a fixed period of time but rather a performance-based standard that is designed to ensure pr otection of USDW’s.

H. Financial Assurance

SEPCo supports EPA’s flexible approach on financial assura nce methods. It would be a mistake to impose any regulatory restrictions that would preclude the u se of particular types of financial assurance or particular instruments, regardless of whethe r those are currently used for other classes of injection wells or in other EPA programs. Allowing for f lexibility recognizes that operators are likely to use combinations of approaches and instruments to m eet these requirements and that these combinations may change significantly over time as operat ors, program Directors and the financial markets gain more experience with geologic sequestration projects. EPA is wise to avoid any artificial constraints on the development of potentially ac ceptable means of achieving financial

assurance.

Recommendation:

Recommend that this approach be retained in the final rule.Letter ID: 0211 Commenter: John King Organization: Shell Exploration and Production Company (SEPCo)

Letter ID: 0211 Comment ID: 22745 Letter Lines: 16 to 57

Comment Code: 1420 1.2.1.1 Support the GS rulemaking

Comment: I. INTRODUCTION

A. Shell Exploration & Production Company (SEPCo) appreciates this opportunity to provide comment to the Environmental Protection Agency (EPA) on its proposed rule regarding Federal Requirements Unde r the Underground In jection Control (UIC) Program for Carbon Dioxide (CO2 ) Geologic Sequestration (GS) Wells.

B. SEPCo strongly supports EPA’s effort to develop appropriate regulations governing CO2 injection for purposes of GS. SE PCo agrees that GS is an important option for the reduction of CO2 emissions , that the UIC program provides an appropriate framework for the regulati on of CO2 injection, and that UIC regulations specifically tailored to CO2 in jection could play a vital role in facilitating the development and implemen tation of GS projects while ensuring that appropriate environmenta l safeguards are in place.

C. As EPA has correctly recognized, it is critical that any UIC program regulation addressing GS be designed to ach ieve two goals. First, 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 and encourage GS as a means to address climate ch ange through the reduction of CO2 emissions to the atmosphere.

D. Fortunately, there is abundant ev idence that CO2 injection can be accomplished in a manner that is protective of human health and the environment. Indeed there has been a long history of successful injection well operation in the United States, and multiple studies have confirmed that the UIC program has been remarkably effective in ensuring protection of human health and the environment. While GS projects are likely to be large in scale, it is important to recognize that the injection of CO2 is nothing new. To the contrary, CO2 has been injected for purposes of enhanced o il and gas recovery (EOR/EGR) for more than thirty-five years, and the UIC progr am already regulates more than ten thousand CO2 injection wells that have su ccessfully injected mo re than half a

billion tons of CO2. We th erefore have a vast body of experience demonstrating that CO2 injection can be conducted without adverse impacts on human health and

the environment.

1E. To achieve its goals for this rule making - to address the risks of CO2 injection and promote the us e of GS to reduce CO2 emi ssions - we ask that EPA utilize more of the successful practices from the experience detailed above in

its final decision on each of the re quirements it has proposed for CO2 injection. SEPCo believes, as further detailed in these co mments that the

Individual Response: EPA believes that the creation of a new injection well class (VI) under the existing UIC Program is necessary to enable the use of GS as a climate change mitigation technology in a manner that protects USDWs from endangerment. EPA agrees that the UIC Program, under the authority of the SDWA, provides a strong fram ework for regulating injection of CO2 for GS and adds that the GS regulati on 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 potenti al presence of impurities in captured CO2, and its mobility within subsurface geologic formations. EPA recognizes that the oil and gas industry has decades of e xperience injecting CO2 for the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS sites. EPA also recognizes that a by-product of ER activities is that a cer tain percentage of the CO2 is trapped in the receiving formation.

Also, since field experience and well constr uction, injection, and m onitoring information relevant to GS comes from operations that inject acid gas or inject CO2 for ER, the Agency has conducted evaluations regarding these commercial field operations and c ontinues to track GSrelevant developments in these commercial operations. Some of the research that informs the

final GS rule was conducted at ER sites.

Letter ID: 0211 Comment ID: 22746 Letter Lines: 57 to 61

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

Comment: injection. SEPCo believes, as further de tailed in these comments that the proposed requirements should be streamlin ed significantly to increase the flexibility of the requirements for CO 2 injection and reduce the unnecessary regulatory burdens the proposed rule would impose. SEPCo respectfully recommends EPA modify its proposed regulat ory approach accordingly.

Individual Response: The Agency believes that the Class VI requirements balance site-specific flexibility with USDW protection. Rather than setting performance or technology-based standards for GS projects, EPA is adopting a 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.

2Letter ID: 0211 Comment ID: 22747 Letter Lines: 70 to 73

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

USDW

Comment: - Lowermost USDW:

- Injection above the lowest USDW should be allowed but the operator should be required to demonstrate confinement above and below the injection formation.

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. It establishes: 1) requirements spec ifying information that owners or operators must submit, and Directors must consider, in consultation with PW SS Directors; 2) procedures for public notice of a waiver application and for Director-Regiona l Administrator communicat ion; 3) the waiver issuance process; and, 4) additiona l requirements that apply to owne rs or operators of Class VI wells granted a waiver of the in jection depth requirements to en sure USDW protection above and below the injection zone.

EPA believes that proper siting, monitoring, and c ontainment capacity are cr itical elements of Class VI injection for GS. However, the Agency also believes that in jection into non-USDW formations above and between USDWs presents unique challenges related to movement of CO2 in the subsurface, which requires a unique approach to ensure that USDWs are protected. Therefore, the Agency believes that additional requirements are appropriate and necessary for wells that would inject into non-USDWs above and between USDWs, including demonstration

of confinement above and be low the injection zone.

Letter ID: 0211 Comment ID: 22748 Letter Lines: 75 to 80

Comment Code: 3560 2.2.3.2 Conditions that merit reevalua tion of the AoR (seeking comment)

Comment: - Area of Review Reevaluation:

- The need for reevaluation of the AOR s hould be required – if at all – when there is site-specific evidence that there is actually a need to reevaluate the AOR. Where monitoring results remain consistent with modeling results, a requirement to reevaluate th e AOR should not be required.

Individual Response: EPA thanks the commenter for their i nput on the types of conditions that could warrant reevaluation of the AoR at §146.84(e) . EPA agrees that site-specific information, including monitoring data, is an important factor in determin ing when AoR reevaluations are appropriate, and expects that the owner or opera tor's and Director's combined knowledge of the local geologic conditions will be a critical elemen t in developing plans th at protect USDWs from

3endangerment.

EPA is developing guidance on AoR and corrective act ion at GS Class VI s ites to assist owners or operators and Directors in how best to evaluate requirements and proposed AoR and corrective action plans under §146.84. The guidance describes EPA's recommended approaches

for the data to be considered in an initial Ao R delineation, how to apply computational modeling to delineate the AoR, performing corrective action at GS sites, and, when appropriate, completing AoR reevaluations. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

Letter ID: 0211 Comment ID: 22749 Letter Lines: 84 to 86

Comment Code: 3820 2.3.1 Well construction procedures

Comment Code: 4500 2.5 Proposed Mechanical Integrity Testing (MIT) Requirements (40 CFR 146.89)

Comment: - The Class VI requirements addressing i ssues such as well construction and mechanical integrity testing should be no different than the Class II requirements.

Individual Response: EPA disagrees with the commenter and believes that significant operational differences between Cl ass II wells and Class VI wells indicate that the Class II requirements are not sufficient to address the di fferences and that Class VI MIT requirements are, therefore, appropriate. For example, the volu me of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Also, reservoir pressure conditions will be different with ER production (extraction) serving to reduce reservoir pressure for Class II operations while Class VI injection operations will have no comparable de-pressuring activities. For these reasons, EPA believes that injection of CO2 for GS projects diffe rs significantly from that of Class II ER operations and warrants more frequent MITs to provide sufficient early warning of the potential for MI failures due to the corrosivity of the CO2 or reservoir pressure

conditions associated with CO2 GS. For additi onal information, please see the discussion of MITs in the final rule preamble.

EPA is using an adaptive approach to regulati ng GS. The Agency plans to collect and review data every six years on early GS projects, in cluding MIT 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.

Letter ID: 0211 Comment ID: 22750 Letter Lines: 88 to 92

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

Comment: - The choice of casing and cement material s should be selected based on planned operating life of the injection well, not the ultimate duration of the GS

4program. The potential for longer-term exposure of well components after injection has ceased will depend upon - a nd can be mitigated by - measures implemented at closure.

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 the 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: 0211 Comment ID: 22751 Letter Lines: 94 to 99

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

Comment: - Site Characterization/Evaluation: EPA s hould seek to develop clear performance

standards as detailed in the American Pe troleum Institute’s submission regarding

site characterization. The need for ad equate site characterization and evaluation cannot be understated, however it is critical that EPA works to clarify the site evaluation needs and en sure that they are no more elaborate than necessary to ensure protection of USDWs.

Individual Response: EPA agrees with the commenter on the importance of proper site characterization, and clarifies that the purpose of th e GS regulation is to en sure that injection of

CO2 for GS is conducted in a manner that is protective of USDWs based on an evaluation of site-specific information. This includes appropria te 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 (under 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.

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 to owne rs or operators regarding char acterizing the regional geology and hydrogeology of a proposed GS site as we ll as performing the n ecessary geochemical, geomechanical, and geophysical analyses of the injection and confining zone. EPA expects that this guidance will assist permit writers in making an objective decision about requiring additional confining layers. The guida nce can be found on EPA’s website at

5http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

Letter ID: 0211 Comment ID: 22752 Letter Lines: 101 to 108

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations

Comment: - Closure and Post-Injection Site Care: Cr iteria for determining the period for post-injection site care should be performance-based and a function of the sitespecific characteristics of a project such as project size, ge ologic factors, and relative risk of the proj ect. (API offers such crit eria in their edits to §146.93(b)(3).) Clear guidelines also need to be established regarding when operators have met the performance sta ndards that determine site closure. Specifically, the standard that the project no longer poses an endangerment to USDWs needs to be defined using reasonable risk-based criteria.

Individual Response: The post-injection site care requirement s in the final GS rule incorporate a combination of a fixed timeframe and a perfor mance standard approach. The final GS rule offer owners or operators flexibility regardi ng the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PI SC timeframe during the postinjection period based on site-specific data , pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Cl ass VI well owner or operator to demonstrate, during the permitting process based on substantial da ta, that an alternative PISC timeframe may be appropriate if it ensures non-endangermen t 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 m onitoring wells; perform post-injection monitoring; demonstrate the appropriateness of an alternative post-injection site care time frame; demonstrate non-endangerment; and perform site closure activities. The guidance will be available at http://water.epa.gov/t ype/groundwater/uic/wells_sequestration.cfm.

Letter ID: 0211 Comment ID: 22753 Letter Lines: 110 to 112

6Comment Code: 5430 2.9.1 Comments on proposed financia l responsibility requirements (40 CFR 146.85)

Comment: - Financial Assurance Provisions: .EPA s hould keep language in the rule that allows for flexibility in the operator’ s ability to utilize an array of

financial assurance tools.

Individual Response: EPA agrees about the need for flexibility, which is why owners or operators may choose from a variety of financ ial instruments to meet their financial responsibility obligations, provided the Director determines that th e operator's proposed financial responsibility demonstration is adequate to protect USDWs from endangerment by paying for each activity for which financial responsibility mu st be demonstrated, including corrective action on wells in the AoR, injection well plugging, PISC and site closure, and emergency and remedial

response.

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 Class VI well owners or operators.

Letter ID: 0211 Comment ID: 22754 Letter Lines: 114 to 120

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

Comment: - Relationships with other Environmental Laws:

- 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.

- EPA should clarify that supercritical CO 2 is not solid or hazardous waste for RCRA purposes and is not subject to any RCRA waste determination requirements.

Individual Response: EPA agrees that any requirements for the CO2 stream should be clearly identified. With respect to RCRA, EPA has deci ded to initiate a separa te proposed rulemaking specifically to examine the issue of RCRA appl icability to CO2 streams being geologically sequestered, including the possible option of a conditional exemption from the RCRA requirements for CO2 GS in Class VI wells. EPA will consider these comments as part of its development of that proposal. The Agency will consider issues pa rticular to RCRA in the context of that separate rulemaking, and recommends that the commenter read that proposed rule when it is published. The Agency notes that comment ers who wish to submit comments on the RCRA proposal will need to do so during the comment pe riod for that rule. Finall y, EPA also notes that the final GS rule, which adds ne w regulations for Class VI wells under the Safe Drinking Water Act (SDWA), is not making any ch anges to the RCRA regulations.

Letter ID: 0211 Comment ID: 22755 Letter Lines: 122 to 125

7Comment Code: 1300 1.1.2.3 Comments on other aspects of CCS (capture, transport)

Comment: - In order to more clearly illustrate the actual risks of CO2 transport and storage, EPA should work to dispel concer ns that geologic se questration could be encumbered with those requirements except possibly through the commingling of a captured CO2 stream with an actual waste stream.

Individual Response: The Class VI GS rule applies to owners or operators of wells that will be used to inject CO2 into the subsurface for the purpose of long-term storage. EPA clarifies that regulating CO2 transportation is outside the scop e of the Class VI GS rulemaking. The Class VI GS rule is designed to ensure consistency in permitting underground injection of CO2 at GS operations across the United States and provide requirements to prevent endangerment of USDWs in anticipation of the eventual use of GS to reduce CO2 emissions.

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 specifically 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.

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.

Letter ID: 0211 Comment ID: 22756 Letter Lines: 129 to 153

Comment Code: 1420 1.2.1.1 Support the GS rulemaking

Comment: A. SEPCo Supports Development of Appropr iate UIC Program Re gulations for GS.

8SEPCo strongly supports the conclusion that the UIC program provides the appropriate framework for regulation of CO2 injection for GS. The UIC program governs a very wide range of underground injection activities - including the operation of tens of thousands of existi ng CO2 injection wells - and enjoys an enviable and extensively documented record of success. The program has in many respects been a model for Federal-Stat e cooperation, and has benefited from a long history of regulatory a nd technical discourse among agencies and regulators armed with considerable practical experience and exceptional technical expertise. While the UIC program is fo cused 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 en sure protection of human health and

the environment.

The UIC program currently provides regul ations that are be ing successfully applied to CO2 injection. Nevertheless, SE PCo agrees with EPA in the need to develop regulations more specifically desi gned to address CO2 injection in the GS context. Our primary recommendation is that such regulations build on relevant UIC program experience, includi ng experience with CO2 injection, and should be tailored to address the par ticular needs 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 reduci ng CO2 emissions. In developing such

Individual Response: As described above, EPA believes that the creation of a new injection well class (VI) under the existing UIC Program is neces sary to enable the use of GS as a climate change mitigation technology in a manner th at protects USDWs from endangerment.

Letter ID: 0211 Comment ID: 22757 Letter Lines: 153 to 159

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

Comment: use of GS as a technology for reduci ng CO2 emissions. In developing such regulations, it is important that EPA ma intain a flexible, performance-based approach that allows regulators to ta ilor specific permit requirements as appropriate based on the broad range of in jection sites and practices that may

be encountered in the GS context and on the body of knowledge and experience that will be gained not only from pilot and demonstration projects, but from the initial deployment of comme rcial scale GS projects.

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

9life 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: 0211 Comment ID: 22758 Letter Lines: 161 to 173

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. SEPCo Supports Continued Application of the Class II Regulations to CO2 Injection in the Enhanced Oil or Gas Rec overy Context and the Creation of "Class VI" Regulations to Address Other CO 2 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 would remain under Class II, and a new classification " Class VI " would be created for GS. This approach makes sense. CO2 injection for purposes of enha nced oil or gas recovery ("EOR/EGR") has been successfu lly regulated as Class II injection for decades, and there is nothing to jus tify any disruption of the existing regulatory regime for the thousands of in jection wells already in use in these operations. For other GS injection projects , Class VI regulations would permit a more structured basis for regulati on than the Class V regulations.

Individual Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas recovery should remain under the Cl ass II Program. However, the Agency believes that the nature and risks of CO2 injection fo r the primary purpose of long term storage poses different risks than injection for the primary purpose of EOR, and therefore has developed new Class VI regulations to address these unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is signifi cantly greater than for EOR operations. Reservoir pressure conditions will also be different, with Class VI injection ope rations involving large volumes of CO2 and likely having higher pressures w ithin their storage formations than Class II ER projects.

Letter ID: 0211 Comment ID: 22759 Letter Lines: 175 to 216

Comment Code: 1210 1.1.1 Comments about the proposed rule

Comment Code: 2064 1.5.3.2 Grandfathering construction of Class II wells (seeking comment)

Comment: C. 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, the proposed rule seems to proceed from the premise that the

10strictest UIC regulations in existence - those for hazardous waste injection - should serve as the starting point for the development of the Class VI regulations. Given the va st knowledge and experien ce developed through the handling of CO2 in different operations, SEPCo contends that the more logical starting point for development of the Class VI regulations is the Class II regulations.

As the proposed rule recognizes, CO2 inje ction operations have been conducted pursuant to the Class II regulations for many years, and experience with thousands of wells injecting hundreds of m illions of tons of CO2 demonstrates that the Class II regulations - as applie d to CO2 injection - are adequate to protect USDWs This is cert ainly true with respect to the basic construction, operating, monitoring, and mechanical in tegrity testing requirements for injection wells; we believe that what "works" in terms of the construction and operation of a CO2 injection well does not depend on the purpose for which CO2 is being injected.

Unfortunately, the proposed Class VI requi rements are far more stringent than the Class II requirements, a fact that gi ves rise - under the proposed rule - to the need to "grandfather" Class II CO2 injection wells that remain in service for GS purposes after oil or gas producti on has ceased. Rather than resembling the Class II requirements, the proposed Cl ass VI requirements are as stringent as those for hazardous waste injection in most respects. Indeed, many of the construction, mechanical integrity, and monitoring and financial assurance requirements proposed for Class VI wells are even more comprehensive and

stricter than those for hazardous waste injection wells. While some of these more burdensome requirements are legitima tely related to concerns about the mobility of CO2 or the anticipated scale of GS operations, many - as discussed

in Part III of these comments - are not.

Recommendation:

The Class VI requirements addressing i ssues such as well construction and mechanical integrity testing should be no different than the Class II requirements.

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).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR requirements) should also be grandfathered. Fo llowing re-permitting of the well as Class VI, many of the unique factors of GS sites (e.g., increa sed reservoir pressures associated with large

11volumes of stored CO2 and the corrosivity of CO 2 in the presence of water) will result in an increased risk profile, warranti ng the specific requirements in the final GS rule. Therefore, following re-permitting as Class VI wells, these proj ects must be subject to the operational, MIT, monitoring, reporting, plugging, and post- injection site care and site closure requirements in the

final GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on these requirements.

Letter ID: 0211 Comment ID: 22760 Letter Lines: 218 to 256

Comment Code: 1680 1.3.8 Don't overstate ris k, don't stigmatize CO2

Comment: D. Rules that Stigmatize GS or Burden it Excessively Would Not be in the Public

Interest.

The magnitude of the regulatory burdens imposed by the proposed Class VI requirements is of concern for several r easons. First, unnece ssary 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 protections addressing the same basic risk - inheren tly magnify the impression of risk and could thus stigmatize GS and deter investment in GS projects.

SEPCo understands the importance of public perception when it comes to the siting and permitting of needed infrastr ucture, and believes strongly in the need to ensure that the public has accurate information to inform it. To facilitate the public’s appreciation of th e merits of GS, SEPCo urges EPA to

ensure that it does not overstate the ri sks associated with CO2 injection or understate the justified confidence w ith which many potential issues and concerns can be addressed Similarly, SEPC o urges EPA to avoid the imposition of regulatory requirements that are so disproportionate to the risks involved that they may do more to amp lify than address public concerns. To this end, EPA should scale back its regulatory requirem ents to more accurately reflect the magnitude of actual risks and to ensure that the requirements imposed are necessary for the prot ection of USDWs.

SEPCo believes that permanent storage of CO2 can be accomplished safely and without harm to the environment by util izing the appropriate knowledge base, detailed site-specific information, technical expertise, a nd sound management practices. It is therefore important th at EPA send accurate messages about the nature of CO2 and the actual magnitude of the risks associated with GS. It is also critical that EPA strike an appr opriate 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 CO2 emissions to the atmosphere.

Recommendations:

12EPA should consider that overly-burdens ome regulation - to the extent it effectively impedes or deters use of a "promising technology" for the reduction of greenhouse gas emissions - could prove environmentally c ounterproductive, given potential operators inabi lity to deploy GS projects.

Individual Response: EPA disagrees that the GS regulation overstates the risk of CO2 injection or that it is “overly burdensom e.” EPA recognizes that injecti ng large volumes of CO2 for GS poses unique challenges that, if not properly managed, could endanger drinking water sources and have other adverse impacts. However, with pr oper site selection, the final, tailored, Class VI requirements address the large volumes of CO2 injected, its buoyancy, potential corrosivity in the presence of water, and pot ential impurities in the CO2 stre am. In addition, EPA expects the tailored permitting, siting, construction, operation, monitoring, and post-injection site care requirements in the GS rule to prevent leakag e from injection formati ons 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.

Letter ID: 0211 Comment ID: 22761 Letter Lines: 258 to 275 ; 920 to 922

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

USDW

Comment: E. Lowermost USDW Restriction

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 protec tion of USDWs and would remove a vast number of viable formations(SEE FOOTNOTE 1) from consideration for GS. Industry has shown that it can operate CO2 injecti on wells in an EOR/EGR context without endangering USDWs that are located belo w 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 ar e other 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.

Recommendation:

Injection above the lowest USDW shoul d be allowed but th e operator must

demonstrate confinement above and below the injection formation.

1) Referring to the Weyburn project, EPA has noted, "The conclusions of Phase I of the project are that depleted oil and gas reservoirs from EOR operations are a promising CO2 storage option ..." 73 Fed. Reg at 43500.

13Individual 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. It establishes: 1) requirements specifying information that owners or operators must submit, and Directors must consider, in co nsultation with PWSS Dir ectors; 2) procedures for public notice of a waiver application and for Director-Regional Administrator communication; 3) the waiver i ssuance process; and, 4) additiona l requirements that apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements to ensure USDW protection above a nd below the injection zone.

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.

Letter ID: 0211 Comment ID: 22762 Letter Lines: 277 to 282

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

Comment: F. 50-year Default Post-Injection Site Care

SEPCO objects to the use of a 50-year default monitoring period. EPA offers no rationale for this arbitrarily selected period of 50 years and establishing a fixed and unusually long time period may create a significant barrier for operators considering entr y into CCS operations.

Individual Response: EPA disagrees with this comment. In determining the post-injection site care-timeframe for the proposed regulation, EP A reviewed industry reports, existing environmental programs, and initial GS research studies. EPA provided a synthesis of pertinent results from GS modeling studies in the preambl e to the proposed regula tion. Further explanation of this analysis was included in an EPA-prep ared background document that is available in the federal docket, titled "Computa tional Modeling of Underground In jection of Carbon Dioxide for

Determination of Area-of-Review and Potentia l Risk to Underground Sources of Drinking Water." Based on review of these studies, m odeling results indicate that the CO2 plume stabilization may occur on the timeframe of 10- 100 years after the cessa tion of injection. EPA believes that a 50-year default post-injection si te care timeframe is a reasonable midpoint for most GS projects and available data, includi ng data submitted by commenters, do not support a different default timeframe, and has reta ined this in the final regulation. However, EPA recognizes that there may be site s where the 50 year post injection site care timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. For this reason, the GS rule o ffers owners or operators flexibility regarding

the duration of the PISC timefra me by: (1) allowing the Direct or discretion to shorten or lengthen the PISC timeframe during the post-in jection period based on site-specific data, pursuant to requirements at §146.93(b) ; or (2) affording the Director discretion to allow a Class

14VI 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 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.

Letter ID: 0211 Comment ID: 22763 Letter Lines: 288 to 382

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

Comment: G. RCRA

SEPCO agrees with the concept that Class VI wells should not be injecting hazardous wastes but is proposing some modi fications to EPA’s de finition 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. SEPCo contends that the question of how CO2 should be accounted for in a GHG management and accounting system is beyond the scope of this regulation. More to the issue of "impurities", SEPCO objects to any mandated purity standards for CO2. The inclusion of impurities in stored CO2 s hould not be arbitrar ily prohibited; however, it is recognized that the pres ence of those impurities at sufficient concentrations may trigger the applicab ility of other statutory limits or requirements. Determining the type and levels of impurities in the CO2 stream is - absent a compelling public or environm ental health risk - best left to contractual negotiations between partners in a CCS va lue chain as opposed to an arbitrary regulatory determination. The c ontracting 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. To the extent that there is an ov erriding public interest in limiting the type or level of contaminants, princi ples of cost-effectiveness and riskmanagement should guide the decision making process.

With specific respect to RCRA, SEPCo is c oncerned that EPA’s brief discussion of a supposed potential for injected CO2 str eams to be characterized as hazardous waste (or some type of hazardous releas e) could have a significant chilling effect on the deployment of CO2 capture and sequestration te chnologies. Based on

15the work of our engineers and scientists with capture technologies and their extensive experience with the types of power plant flue gas like ly to be sources of CO2 for sequestration, we do not belie ve that captured CO2 streams should trigger the application of RCRA. In addition, EPA’s Proposal suggests that injected CO2 may be considered hazar dous waste for RCRA purposes, and defines "carbon dioxide stream" to exclude hazardous waste. 73 Fed. Reg. at 43503. The premise appears to be that CO2 is solid waste, and that a waste determination for such solid waste would turn on the specific composition of the CO2 in question. Id. Based on this premise, the preamble suggests, "EPA cannot make a categorical determination as to whethe r injected CO2 is hazardous waste under

RCRA." Id.

Rationale:

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.

The RCRA definition of solid waste is lim ited to "solid, liquid, semi-solid, or contained gaseous material." RCRA 1004(27). Because supercritical CO2 is none of these things; a plain readi ng of the statutory text s uggests that supercritical

CO2 should not be considered "solid wast e." This reading of the statute makes sense, because RCRA is plainly aimed at th e kind of material that could end up being dumped into a landfill. Uncontained supercritical CO2 is not such a material. Instead, the physical properties of supercritical CO2 are such that it would immediately vaporize -- becoming an uncontained gas -- before it could

contribute to the contents of a landfill. A related pract ical consideration is

the fact that the hazardou s characteristics -- the broad waste determination criteria that provide a pr imary means for determining when solid waste is hazardous waste -- are based largely on test methods that are inapplicable to materials such as supercritical CO2. In pa rticular, the toxicity characteristic depends on test methods that can only be a pplied to materials th at are solids or liquids at standard temperatures and pr essures. This is unsurprising, because the toxicity characteristic was designed to assess the threat waste would have in a municipal landfill disposal scenar io, a scenario that -- as already discussed -- is inherently inapplicable to supercritical CO2. Accordingly, it makes no legal, policy, or practical sens e to treat uncontaine d supercritical CO2 as "solid waste" for RCRA purposes. EPA should therefore confirm that uncontained supercritical CO2 is not "solid waste" and is not subject to RCRA waste determination requirements.

It follows that a CO2 stream would only qualify as "solid waste" if it is

16actually 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.

Recommendations:

There are important categorical determinati ons that EPA can and should make with respect to the RCRA status of CO 2. SEPCo recommends the following:

1. 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.

2. EPA should clarify that supercritical CO2 is not solid or hazardous waste for RCRA purposes and is not subject to any RCRA waste determination requirements.

3. In order to more clearly illustrate the actual risks of CO2 transport and storage, EPA should work to dispel concer ns that geologic se questration could be encumbered with those requirements except possibly through the commingling of a captured CO2 stream with an actual waste stream.

Individual Response: With respect to RCRA, EPA has decide d to initiate a separate proposed rulemaking specifically to examine the issue of RCRA applicability to CO2 streams being geologically sequestered, including the possible option of a conditional exemption from the RCRA requirements for CO2 GS in Class VI wells. EP A will consider these comments as part of its development of that proposal. The Agency w ill consider issues par ticular to RCRA in the context of that separate rulemaking, and recommends that the commenter read that proposed rule when it is published. The Agency notes that commenters who wish to submit comments on the RCRA proposal will need to do so during the comme nt 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 maki ng any changes to the RCRA regulations.

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: 0211 Comment ID: 22764 Letter Lines: 386 to 456

Comment Code: 3140 2.1.4 Comments that the proposed ge ologic data requirements are too stringent

Comment: A. Geologic Siting Requirements

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 low17permeability confining zone with sufficien t thickness and lateral extent to protect overlying USDWs. 73 Fed. Reg. at 43505. These are familiar and appropriate requirements, and they appear to be appropriately embodied in the regulatory text proposed fo r codification at 40 C.F.R. 146.83(a). Unfortunately, the preamble goes on to suggest the need fo r extraneous detail in the evaluation of site conditions. In addition, the rule text proposed for codification at 40 C.F.R. 146.83(b) would allow the Administ rator apparently unlimited discretion to impose additional siting requirements that go beyond those necessary to ensure protection of USDWs.

Recommendation:

EPA should omit the latter requirement of extraneous details, and instead seek to develop clear performance standards as detailed in the American Petroleum Institute’s submission regarding site ch aracterization. The need for adequate

site characterization cannot be understated, however it’s is critical that EPA works to clarify the site evaluation needs and ensure that they are no more elaborate than necessary to en sure protection of USDWs.

1. Site Evaluation

The preamble appears to suggest that th ere may be a need for an elaborate

evaluation of site conditions to address concerns related to seismicity and potential geochemical interactions. In f act, however, seismicity and geochemical compatibility are issues that are easily addressed in the GS context, and requirements for unnecessarily elaborate an alysis would serve only to burden and impede the development of GS projects.

Concerns with respect to seismicity are frequently raised in the injection well context, but there is ample experience 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 seri ous problems in the GS context. These conclusions are confirmed by decades of experience with thousands of Class II CO2 injection wells injecting hundreds of millions of tons of CO2.

While it is true that injection of CO2 can be expected to lead to the formation of carbonic acid, the resulting carbonic acid is only weakly corrosive and -- as experience with the injection of extr emely corrosive hazardous wastes demonstrates -- cannot reasonably be expected to cause any breach of containment that would endanger a USDW. The proposed ru le expresses specific concern about geochemical reactions that could alter the composition of the injected CO2 stream -- particularly through the mobili zation of contaminants that occur naturally in the injection zone -- but such concerns are immaterial because the specific composition of the CO2 stream matte rs little as long as the CO2 remains

confined. Another theoretical concern relates to the pot ential for geochemical

18changes to contribute to the plugging of pore spaces in the injection zone. However, experience with Class II CO2 in jection confirms po re plugging should not pose any practical problems in the CO 2 injection context because of the

relative weakness of carbonic acid and the time and tr ansport distance required for carbonic acid to form and for any subse quent geochemical changes to occur. Even if pore plugging were to manifest it, it would occur deep in the injection zone where its effect would be minimal. In any event, the impact of pore plugging would only be to decrease permeab ility in the injection zone, thereby reducing the efficiency (but not the safety) of the injection operation.

In short, geochemical changes related to CO2 injection cannot be expected to be material to the protection of USDWs. Acco rdingly, there is no credible basis for the suggestion (73 Fed. Reg. at 43505) that"[s]tudies of rock samples and review of geochemical data from monito ring wells are needed to evaluate the impact" of potential geochemical ch anges related to CO2 injection.

Recommendation:

Remove requirements for detailed analysis of potential chemical or mineralogical reactions that are unnecessary to ensure protection of USDWs.

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 injection 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 ma y reduce the need for a dditional injection wells which reduce the potential for unacceptable fl uid movement and improve USDW protection from endangerment.

19Finally, EPA disagrees that any of the requirements for detailed anal ysis of potentia l chemical or mineralogical reactions are unnecessary to en sure protection of US DWs from endangerment. EPA believes that information on the mineralogy of the injection and confining zones (required at §146.82(3)(iii)), can help predict geochemical reactions between the injectate, reservoir geology, and formation fluids. Such reactions can lead to dissoluti on and precipitation of minerals which can affect formation porosity and injectivity, and in turn can affect required injection pressure (Sminchak and Gupta, 2002) a nd transport of fluid within the formation.

Additionally, EPA disagrees that c onsideration of local and regiona l seismicity 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: 0211 Comment ID: 22765 Letter Lines: 458 to 485

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 Administrator discretion to require, a dditional confining and containment zones above the primary confining zone. 73 Fed. Reg. at 43505-06. SEPCo strongly opposes any such requirement.

Rather than being necessary for the pr otection of USDWs, a requirement for additional confining and containment zones above the injection zone would apply in addition to the requirement for an ade quate demonstration th at USDWs will be protected. By definition, such a requirem ent is unnecessary. Having demonstrated the adequacy of their belts, there is no need to require permit applicants to furnish suspenders as well.

It should also be noted that a requi rement for additional confining and containment zones above the injection z one would be unprecedented. No such requirement exists in the UIC program, ev en in the context of hazardous waste injection. Nor does such a requirement appl y in any of the countries where GS projects are currently un derway (including Norway, Canada, Australia and Algeria). EPA should not singl e out GS for heightened and substantially more rigorous requirements than would be warrant ed on the merits of the actual risk.

Recommendation:

20Require potential operators to demonstrate that USDWs will not be endangered by the proposed injection activity in the primary containment zone through the Class VI permitting process, without a dding a requirement of any secondary confining or containment zones.

Individual Response: EPA believes that the Class VI requir ements, including the level of site characterization required under §§146.82 and 146.83, appropria tely address the unique challenges posed by large-scale GS including large injection vol umes, the relative buoyancy of CO2, its corrosivity in the presence of water, th e potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations. The Agency believes that in some geologic settings, the presence and identification of additional confining and containment zones above the primary (i.e., lowermost) confining zone can improve USDW protection. These formations could further impede vertical flui d movement, allow for pressure dissipation, and provide additional sites for monitoring, mitigatio n, and remediation, while also affording the greatest protection of USDWs from endangerment. 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: 0211 Comment ID: 22766 Letter Lines: 487 to 498

Comment Code: 3310 2.2.1.1 Comments in favor of requiring computational models to delineate the AoR (seeking comment)

Comment: B. Area of Review and 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 penetrations such as abandoned boreholes. The use of such modeling is already

well established in the c ontext of oil and gas expl oration and production and has been used in the UIC program for "no-migration" petitions for hazardous waste injection. Similar modeling can reas onably 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). Models can predict CO2 fate and tr ansport, as well as changes in formation pressure, in three dimensions, as a function of ti me in order to delineate the subsurface storage site and the AoR. Models can account for site-specific and predicted operating conditions as well as geologic heterogeneities a nd potential migration through fau lts, fractures, and artificial penetrations.

21Letter ID: 0211 Comment ID: 22767 Letter Lines: 500 to 529

Comment Code: 1220 1.1.1.1 Terminology and definitions

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

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 computation mode ling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream." Id.

There are two 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 shows, it is ra rely necessary to attempt to model chemical changes in the injectate plume. Indeed, it is typically far easier to model transport than chemical fate, a nd 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 plume -- rather than the precise composition of the pl ume -- that matters, and modeling of chemical changes would be unnecessary. Sim ilarly, the preamble suggests that the "most sophisticated" and most "accurate" modeling should be preferred or even required. 73 Fed. Reg. at 43507. Again, howev er, the appropriat e goal is to ensure protection of USDWs, and simpler, more conservative modeling may often be sufficient (and even preferable) for this purpose.

Second, 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 US DW’s, and it should be.

Individual Response: EPA believes that predicting the comp lex 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

22precision 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.

Letter ID: 0211 Comment ID: 22768 Letter Lines: 531 to 547

Comment Code: 3400 2.2.2 Corrective Action

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

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 periodic reassessment of the AOR and a phased implementation of corrective action. In general, this approach is prudent and practical, providing what will ultimately be a rigorous approach to corr ective action while reducing regulatory burdens by permitting a phased implementation of corrective action requirements. However, SEPCo does not believe that a minimum frequency for reevaluation of the AOR should be required.

Recommendation:

The need for reevaluation of the AOR shoul d be required -- if at all -- when there is site specific evidence that there is actually a need to reevaluate the AOR. Where monitoring results remain consistent with modeling results, a requirement to reevaluate th e AOR should not be required.

Individual Response: EPA believes that periodic AoR r eevaluation at a set frequency is necessary to ensure protecti on of USDWs from endangerment and address the uncertainties inherent in predictive modeling. Periodic Ao R reevaluations at §146.84( e) ensure that a deliberate effort is made to verify, based on m onitoring and operational da ta, that the CO2 plume is moving within the subsurface as predicted. EP A believes that less frequent reevaluations or planning reevaluations only when a need is dem onstrated may not be sufficient to appropriately model plume and pressure front movement, estab lish conditions for corre ctive action, and ensure protection of USDWs from endangerment. EPA ag rees that site-speci fic factors should be considered in the reevaluation schedule, and notes that the AoR and corrective action plan must specify the site-specific mon itoring and operational conditions that warrant reevaluation, as specified in §146.84(b)(2)(ii).

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

23that the current AoR delineation is ad equate based on site monitoring data.

Letter ID: 0211 Comment ID: 22769 Letter Lines: 549 to 583

Comment Code: 3820 2.3.1 Well construction procedures

Comment: C. Injection Well Construction Requirements

1.Well Design

Many years of experience with the Class II UIC program -- including 35 years of CO2 injection in the EOR context -- have demonstrated that the construction requirements for Class II injection wells 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 specifically cites th e buoyancy of CO2 as the justification for these requirem ents. See 73 Fed. Reg. at 43509.

SEPCo argues that the buoyancy of CO2 in no way justifies the additional construction requirements proposed. The reas on for this is straightforward: by far the greatest driving force for fl uid migration along an injection well borehole is the pressure build-up (or "cone of influence") caused by fluid injection during the operati on of the injection well. The magnitude of this pressure influence is at its maximum at the point of inject ion, and -- within the injection interval -- it generally fa lls off logarithmically with lateral distance from the injection well borehole. At some distance from the injection well, the pressure influence of the in jection activity can be expected to decline to the point where density-driv en flow (i.e., buoyancy) could become significant (at least in relative terms) as a driver for vertical fluid migration. At the injection well, however, the induced pressure gradient caused by the injection activity woul d so dwarf the impact of buoyancy as to render the latter insignificant.

In short, buoyancy can be significant as a driver for lateral fluid movement, but provides a relatively weak driver for vertical flui d flow that -- at the point of injection -- is in significant in comparison to the pressure gradients caused by injection. Accordingly, it woul d be unreasonable to suggest that buoyancy justifies significantly more de manding injection we ll construction requirements than have already proven to be sufficient in the case of Class II CO2 injection wells.

Individual Response: As described above, EPA believes that GS is sufficiently different from Class II ER operations to warrant the tailored constr uction requirements for Class VI wells at §146.86.

24EPA disagrees that buoyancy is not a consideration that needs to be addressed in the GS regulations. Field and laboratory studies that evaluated two d eep wells exposed to CO2 for nearly three decades have provide d evidence of upward vertical flow of CO2. In Carey, et al. (2007), a sample of well cement collected from a section of well in the confining zone at

SACROC showed evidence of cemen t alteration (carbonation) due to exposure from CO2. (The study was not able to determine whether the al teration was due to exposure to CO2 in the presence of water, dry CO2, or to a CO2-brine mixture.) In Crow, et al. (2009), a similar study was conducted on a CO2 production well that was dr illed into and comple ted 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 overlying caprock or by upward CO2 migration within wellbore system defects (perhaps cement-caprock and/or cementformation interfaces). In both studies, the CO2 apparently moved from the underlying reservoir

into the well bore section located within the ove rlying caprock. These obser vations, especially in conjunction with the larger CO2 volumes and hi gher 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 we ll 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 3 years after injection began. The ove rall behavior of CO2 at Sleipner is for it to migrate to the top of the formation and spread laterally from th ere (Chadwick, et al. 2006). Additionally, CO2 has the potential to be corrosive (in the presence of water or aqueous formation fluids during CO2 injection), and the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II ER/ CO2 injection wells.

Letter ID: 0211 Comment ID: 22770 Letter Lines: 585 to 600

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment)

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

Comment: SEPCo nevertheless supports the requirem ents for a surface casing cemented to the surface, for injection through a tubi ng and packer, and for a well design that permits continuous monitoring of a pressurized annulus. The requirement SEPCo finds objectionable is that for continuous cemen t along the entire longstring casing. This requirement -- while appropriate for hazardous waste injection wells -- is simply 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 th is performance standard are heavily dependent on site-specific conditions and are most appropriately determined in the permitting process.

Recommendation:

25Utilize Class II well construction standards for the Class VI program. The proposed design standard mandating conti nuous cement for the long string casing should be deleted as unnecessary and unduly burdensome.

Individual Response: EPA believes that the requirements fo r long-string casing are appropriate and offer appropriate flexibility : §146.86(b)(3) requires th at the long-string casing extend to the injection zone and be cemented by circulating cement to the surface in one or more stages. It does not, however, specify how cementing would be accomplished, and gives flexibility to the owner or operator to propose alternate methods to provide a sufficient amount of cement to meet the standard that USDWs are pr otected from endangerment, s ubject to the approval of the

Director.

EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing. See the discussion of Class VI well cons truction requirements in the preamble to the

final GS rule for additional information. A dditionally, EPA is developing guidance on the construction of Class VI wells. This guida nce will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

EPA adds that other aspects of the rule allow flexibility based on site-s pecific considerations: with their permit applications, owners or operators must submit proposed well construction procedures, as specified at §146.82(a)(12), that address the specific drilling and injection environment and the chemical and physical nature of the CO2 injected stream. The Director must evaluate the appropriateness of the proposed c onstruction based on site-specific information about the injection project, including injection pressures, injection a nd confining zone lithology,

and information about the carbon dioxide stream , as provided in the final GS rule at §146.86(b)(1).

Letter ID: 0211 Comment ID: 22771 Letter Lines: 602 to 648

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: 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 stream s would often (if not generally) be

26"dry"(i.e., dehydrated) and therefore non- corrosive. Once injected, the "dry"

CO2 would come into contact with natura lly-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, cr eating a plume of relatively pure CO2 surrounding the point of injection. While CO2 would mix with

water around the boundaries of this plume, the plume its elf would continue to consist of relatively dry (and therefor e non-corrosive) CO2. In this situation -- which can be expected to be typica l in the carbon seque stration context -- there is no basis to suggest that injected CO2 is corrosive or that injection wells must be designed and constructed to resist a partic ularly corrosive

environment.

Class II experiences with CO2 injection supports this conclusion. Corrosion is an issue for injection wells used to produce "wet" streams containing oil, brine, and CO2 fractions brought up in the course of EOR/EGR operations (which may contain significant carbonic acid). Howeve r -- and this is the point that is relevant to the GS context -- "dry" CO2 injection systems have operated for many years without the need for corrosion-resist ant construction or the occurrence of corrosion-related problems.

Well 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.

Recommendation:

The choice of casing and cement materials should be selected based on planned operating life of the injection well, not the ultimate duration of the GS program. The potential for longer-term exposure of well components after injection has ceased will depend upon -- a nd can be mitigated by -- measures implemented at closure.

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. The rule does not specify material s to be used; rather, it provides owners or operators with the flexibility to choose, as l ong as the materials used in Class VI wells are compatible with fluids with which they may co me into contact and meet or exceed standards developed for such materials by API or ASTM In ternational, or comparable standards approved by the Director, as provi ded at §146.86(b)(1).

EPA clarifies that it is when CO2 is in the presen ce of water or formation fluids that it can be

27corrosive to well materials. Reference to corros iveness of the CO2 str eam in §146.86 is intended to mean CO2 in the presence of water or formati on fluids. EPA also notes that while a "dry out zone" (i.e., an area that is free of liquids) might form during injection (e .g., Birkholzer, et al. 2008), no modeling study or other information is available about the post-injection period. At some point in the post-injection period, the near-wellbore environment may again become hydrated increasing the risk of cement corrosion. Several studies in cluding field, laboratory, and modeling studies have found that pH drops in the formation fluid, indica ting at least partial mixing of the carbon dioxide and formation water (Kaszuba, et al. 2005; Kharaka, et al. 2006; Birkholzer, et al. 2008). The risk of creating acidic fluids that c ould come in contact with well materials and cements is addressed by the construction requirement s 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.

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: 0211 Comment ID: 22772 Letter Lines: 650 to 691

Comment Code: 4110 2.4.1.1 Injection pressure limitations

Comment Code: 4120 2.4.1.2 Allowing hydraulic fracturing during GS (seeking comment)

Comment: D. Injection Well Operating Requirements

1. Injection Pressure Limitations

Under the existing UIC regulations, permits for Class II injection wells must limit injection pressure as follows:

Injection pressure at the wellhead shall not exceed a maximum, which shall be calculated so as to assure that the pressu re during injection does not initiate new fractures or propagate existing fractures in the confining z one adjacent to the USDWs. In no case shall injection pre ssure cause the movement of injection

28or formation fluids into an underg round source of drinking water.

40 C.F.R. 146.23(a)(1). This has proven to be an effective regulatory requirement that provides a flexible and a ppropriate performance standard to be applied on the basis of site-specific condi tions. This regulatory approach has proved successful in the Cl ass II context, and there is no basis to conclude

that a similar standard would not be appropriate in the context of carbon sequestration.

The Class I requirements impose more rest rictive requirements designed not just to prevent endangerment of USDWs, but to ensure that there is no fracturing in the injection zone during normal operati on. The latter requir ement may make sense when "no migration" exemptions de pend upon the integrity of confining or "arrestment" strata within the injec tion zone, but such a requirement is certainly more rigid than necessary to prevent endangerment of USDWs. Accordingly, such a standard is not necessary in the c ontext of carbon sequestration, and would be il l-suited in a rule that must have the flexibility to address a wide range of pot ential injection scenarios.

Recommendation:

Injection pressure limitations for Class VI injection wells should be based on the existing Class II requirements, modified slightly to address the possibility of Class VI injection occurring above th e lowermost USDW. We recommend the following specific language:

Injection pressure at the wellhead shall not exceed a maximum, which shall be calculated so as to assure that the pressu re during injection does not initiate new fractures or propagate existing fractur es in the confining zone. In no case shall injection pressure cause movement of injection or formation fluids that endangers an underground s ource of drinking water.

Individual Response: EPA believes that the injection pressure limits in the GS rule are important to protect against fr acturing of the confining zone, and that the requirement at §146.88(a) that the pressure in the injection zone not exceed 90 percent of the fracture pressure provides a margin of safety in the well operati on and protects USDWs from endangerment.

The pressure limitations are tailored to the unique nature of CO2 injection for GS and afford flexibility to address site-speci fic circumstances. EPA notes that during the site characterization process, owners or operators must submit data about the geology of the site, as specified at §146.82(a), including data on known or suspected faults and fractures and geomechanical information on fractures, stress, ductility, rock strength, and in s itu fluid pressures within the confining zone. The Director will use these data to determine appropriate limits on injection.

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.

29The 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/groundwat er/uic/wells_sequest ration.cfm. The Department of Energy is developing a Best Practices Ma nual on site characterization.

Letter ID: 0211 Comment ID: 22773 Letter Lines: 693 to 702

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment)

Comment: 2. 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 would be cost ly and is completely unprecedented in the UIC program. Down hole shut off valv es would increase well construction and operation costs, and could significantly complicate well testing and workovers. Class I hazardous waste injection wells are not required to have down- hole automatic shut-off valves, and there is no basis to suggest that CO2 injection entails higher risks warran ting costly additional safety measures that would interfere with monitoring and potentially with any necessary well remediation.

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. However, the Agency believ es that offshore Class VI wells present unique construction and operational conditi ons, including isolation from shorelines and the need to construct wells through the water column and the subsurface, which may delay response time in

the event of well difficulties. Th e rule requires, at §146.88(e)(3), that owners or operators of

offshore wells within State territorial waters install automatic down-hole shut-off systems. EPA believes that these requirements at §146.88(e) ensure that proper precautions are taken to prevent

subsurface fluid movement and ensure protection of USDWs.

EPA clarifies that down-hole shut-off devices are cu rrently used in situa tions where loss of well integrity could result in damage to the well or harm to humans (e.g., ne ar high-density population areas, or in onshore acid gas inj ection; IEA, 2003). EPA has identi fied examples of documented logging techniques, including ultr asonic and temperature logs, th at can be performed with an automatic down-hole device emplaced (Julian, et al. 2007; Somaschini, et al. 2009). They are also used in high pressure, high temperature onshore wells and in permafrost areas.

EPA believes that requiring auto matic surface shut-off devices instead of down-hole devices for onshore wells provides more flexibility to ow ners or operators when performing required

30mechanical integrity tests. A dditionally, this requirement a ddresses concerns about risks associated with routine well workovers that may be complicated by the presence of down-hole devices while still maintaining USDW protection.

Letter ID: 0211 Comment ID: 22774 Letter Lines: 704 to 709

Comment Code: 4250 2.4.3 Corrosion monitoring and control

Comment: 3. Corrosion Monitoring

As already discussed, CO2 is not corrosive in the absence of water and there is no basis to assume that carbon sequestrati on wells will typically or even often be injecting corrosive fluids. A general requirement for corrosion monitoring is therefore unnecessary and inappropriate.

Individual Response: EPA disagrees with the commenter's assertion that corrosion monitoring is unnecessary or excessive. CO2 in the presen ce 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 targ et 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; Aker voll, 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 addresse s the effects of corrosion of stee l 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 fieldbased 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

31well failure, EPA believes that corrosion monitoring in the down-hole environment is justified in order to protect USDWs from endangerment.

Letter ID: 0211 Comment ID: 22775 Letter Lines: 711 to 731

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: 4500 2.5 Proposed Mechanical Integrity Testing (MIT) Requirements (40 CFR 146.89)

Comment: E. Mechanical Integrity Te sting (MIT) Requirements

The proposed rule suggests, "MIT requirement s for GS wells should be tailored to address the unique properties of CO2, specifically its buoya ncy and potential corrosivity." 73 Fed. Reg. at 43513. As pr eviously discussed, however, the buoyancy of CO2 is a relatively trivial f actor in relation 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 sugges t that the buoyancy of CO2 is relevant

to be considered in esta blishing mechanical integrity testing requirements for GS wells. Similarly -- as also previously discussed -- CO2 is not corrosive and cannot be expected to cause corrosion pr oblems for the injection well (including down-hole cement) unless the CO2 stream its elf contains water. Consequently, corrosion generally should not be expected to be a problem and concerns related to corrosion do not justify any particularly stringen t requirements for GS wells. Experience with CO2 in the EOR c ontext 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.

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 othe r classes of wells and injectates regulated by the UIC Program.

Supercritical 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 preferentia lly through fractures. Such migration could

32occur 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.

Letter ID: 0211 Comment ID: 22776 Letter Lines: 733 to 760

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 CFR 146.90)

Comment: F. Testing and Monitoring Requirements

The preamble to the proposed rule indi cates, "EPA considers CO2 plume and associated pressure front monitoring to be necessary for verification of model predictions." 73 Fed. Reg. at 43514. This is difficult to understand because the

33regulatory regime for Class I hazardous waste injection wells do not require elaborate modeling, and plume or pressure front monitoring have never been considered necessary and are not required in that context. In fact, extensive experience with Class I hazardous waste in jection demonstrates that plume and pressure front monitoring is not necessa ry, either to provide confidence in modeling results or otherwise. By sugge sting otherwise, the proposed rule unnecessarily undermines confidence in the modeling demonstrations that can and should be relied upon to suppor t determinations that injected CO2 will not endanger USDWs.

The suggestion that it makes sense to mon itor the movement of injected CO2 in

the subsurface also does not consider the nature and util ity of modeling used to evaluate injection well projects and of the technical difficulties and uncertainties such monitoring would involve . The root of the problem relates to the fact that modeling provides a conservative assessment of the potential for movement of injected fluids in the subsurface, not a precise "prediction" of actual fate and transport that can or should be "verified" on the basis of elaborate, costly, and uncertain efforts to observe the actual movement of fluids in the subsurface. As experience with hazardous waste injection shows, injection well operational data and the results of pressure fall-off tests provide ample data to validate the results of modeling. The additional monitoring requirements proposed in th e GS context are excessive and unjustified.

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.

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.

The final rule, at §146.90(g)(2) requires owners or operators to track the position of the CO2 plume using indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools), un less the Director determines based on site-specific geology,

34that such methods are not appr opriate. For example, geophysical methods are difficult to execute in areas that are structurally and topographically complex or where lithologies have limited contrast in density, porosity, permeability, and ot her physical properties. EPA clarifies that this determination will be made by the Director ba sed on the site-specific geologic information submitted by the owner or operato r with the permit application.

EPA believes that this approach provides flexibility to develop a site-specific monitoring plan, ensures that direct monitoring is available to track the movement of the CO2 and validate models, and recognizes that indirect techniques are not appropriate in all situations. The owner or operator's approved testing and monitoring pl an will include the site-specific details, technologies, testing and monitoring freque ncies, and other pertinent information.

EPA agrees that good site selection, modeling, and management are crucial elements of a successful GS project, but disagrees that this is an effective substitute for rigorous site monitoring. EPA disagrees that pressure fall-off te sts are an appropriate substitute for monitoring pressure changes in the injection zone. Pressure fall-off tests provide information only in the vicinity of the injection well(s) and measure pressure conditions within the injection zone only. Direct monitoring of pressure changes in the injection zone can provi de advance warning of

movement of CO2 or brine that mi ght ultimately endanger a USDW.

Letter ID: 0211 Comment ID: 22777 Letter Lines: 762 to 772

Comment Code: 4660 2.6.6 Geochemical monitoring

Comment: Suggestions that it should be necessary to monitor geochemical changes or to study interactions between brine and CO2 in the injection zone are particularly troubling, because detailed information c oncerning such interactions should rarely if ever be relevant from a regulatory standpoint. In particular, USDWs are generally protected by ensuring that in jected fluids will remain isolated from them, and experience with hazardous waste injection " wh ere the injection of highly corrosive waste is not unco mmon " has shown that geochemical

interactions that could ac tually compromise containment cannot reasonably be expected in the absence of truly unusual circumstances. Accordingly, any general requirement to monitor geochemical ch anges in the subsurface would be

unreasonable.

Individual Response: EPA disagrees with the commenter. While contamination is unlikely at properly selected, constructed, and operated si tes, EPA believes that robust monitoring is necessary to ensure that USDWs are protected.

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.

35EPA 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_sequestration.cfm.

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

Letter ID: 0211 Comment ID: 22778 Letter Lines: 774 to 782

Comment Code: 4650 2.6.5 CO2 plume and pressure fr ont tracking (seeking comment)

Comment: 1. Monitoring CO2 Movement and Reservoir Pressure

The 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 an assertion that cannot be reconciled with experience with Class I hazardous waste injection, where such monitoring has never been cons idered 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.

36EPA 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: 0211 Comment ID: 22779 Letter Lines: 784 to 811

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 CFR 146.90)

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-existe nt -- they have li ttle potential to provide more than an isolat ed "point measurement." If the object is to track injected fluid within an injection zone , a monitor well could be placed in the path of the waste front to detect th e waste front when it goes by, but the exercise would amount to a very expensive way to generate a single data point. There would be less likelihood of any benef it from monitoring wells designed to detect potential leakage from an injecti on zone, because the ability to detect such leakage is at best a hit-or-mi ss (if not a needle in a haystack) proposition. Monitor wells also have bu ilt-in confounding factors that include both the potential for well c onstruction to impact fluid quality in the target sampling interval and the fact that sa mpling may itself cause fluid movement that might not otherwise occur. Because pr essure fronts extend much further than injected fluid plume fronts during injecti on, pressure monitoring is more likely to be useful than fluid sampling, but costs would till be very high and the ability to detect relevant changes would still be very much hit-or-miss. For these reasons, EPA chose not to impose monitor well requirements for Class I hazardous waste injection wells, though it did allow monitor wells to be required at the discretion of the Ad ministrator to address particular

circumstances at the site. See 52 Fe d. Reg. 32446 at 32463-64 (August 27, 1987), 53 Fed. Reg. 28118 at 28141, 28144-45 (July 26, 1988). Experience with hazardous waste injection does not commend the use of monitor wells even in that context, and there is no justification to impose as stringent an approach -- let alone a more stringent approach -- for the injection of CO2.

Individual Response: As described above, EPA believes th at monitoring using wells in the injection zone, e.g., for pressure monitoring as required at §146.90(g )(1), can be safely

37performed if the wells are constructed to preven t flow between the injec tion zone and USDWs or other layers above the confining zone. Such construction technologi es exist and have been used in the oil and gas industry for years. EPA believes that properl y constructed monitoring wells will be a safe way to obtain the da ta that is essential to ensure that the injected CO2 remains confined in the injection zone and that pressu re 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 describe s how the owner or operator plans to site and construct monitoring wells. EPA is developing guidance on well construction that will include recommendations for monitoring well constructi on. The guidance will be available on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_sequestration.cfm.

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.

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 and 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 sites. 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).

Letter ID: 0211 Comment ID: 22780 Letter Lines: 813 to 829

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

38possible to use remote geophysical techni ques for "plume tracking." 73 Fed. Reg. at 43515. Unfortunately, it is not clear that there are establis hed technologies available that are sufficiently reliable and mature in their development for application in a regulatory context. In general, the tec hnologies available would be very expensive to employ on the scale required, and pr ovide inferential data that is subject to considerable interpretation. Such techniques are unsuitable for required use in a regulatory context.

The problem with interpretive tests is that they are interpretive and therefore inherently subject to uncertainties. The suggestion that such techniques could be used for "plume tracking" to "verify" the results of modeling is optimistic at best, and creates unrealis tic expectations for the t echnologies involved. In fact, the use of such techniques may do mo re to amplify residual uncertainties and thereby undermine public confidence in GS.

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 also required unless the Di rector determines, based on s ite-specific geology, that such methods are not appropriate.

EPA 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.

There may also be interference from urban and re sidential infrastructure, and sites with loose materials such as glacial deposits may produce poor or inaccurate seismic images. But the laterally continuous, confined formations that make many sites appropriate for GS will also render many of them suitable for seismic survey ing. In fact, seismic and other geophysical and remote sensing methods have been used with suc cess at GS pilot projects and are likely to be useful for plume tracking at many GS sites. St atOilHydro has used both time-lapse seismic and gravity methods to track the CO2 plume at the Slei pner site. Seismic surveys have also been used successfully at the Weyburn pilot project site in Saskatchewan. Although resolution on seismic surveys is generally accepted to be the best of the geophysical methods, gravity monitoring at Sleipner has also imaged the plume, and results have agreed with seismic surveys. At InSalah, PSInSAR satellite monitoring has been used in co mbination with tiltmeter data and was able to detect otherwise imperceptible ground displacement (i.e., at the millimeter scale) that indicates the presence of CO2.

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

39guidance 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_sequestration.cfm.

EPA disagrees that monitoring at GS sites will undermine public confidence in GS and the UIC Program. EPA believes that appropriately desi gned and implemented monitoring plans will increase public confidence in the safety of GS, helping to assure the public that any problems are detected early and that appropr iate measures are taken to pr otect USDWs from endangerment. Knowledge of the location of the CO2 plume and the associated pressure front will enable EPA to assure the public that GS projects are pr oceeding 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: 0211 Comment ID: 22781 Letter Lines: 831 to 851

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. EPA has pr oposed elaborate -- and in many cases overly-elaborate -- requirements to en sure that this goal is achieved. Consequently, it is difficult to imagin e how requirements for surface air or soil gas monitoring could be justified.

As EPA seems to recognize, surface air or soil gas monitoring would impose

substantial costs and the re sults of such monitoring w ould be subject to a host of confounding factors. Worst of all, such monitoring w ould be aimed at leakage of CO2 all the way to the surface, wh ich -- in the case of any properlypermitted GS project -- would by defin ition be an extraordinarily low probability scenario.

Recommendation:

Surface Air and Soil Gas Monitoring should not be imposed, nor should regulators have discretion to impose them. The poten tial for possible leakage pathways should be demonstrated and manage d during the permitting process.

Individual Response: EPA clarifies that subsurface geochemi cal and pressure monitoring in the

subsurface formations are the first line of m onitoring that would allow detection of potential endangerment to USDWs from GS ac tivities (this is required at al l GS sites, as described at

40§146.90(d)).

The Agency also believes that su rface air and soil gas monitoring, when coupled with subsurface monitoring, may be appropriate at some GS projects to ensure USDW protection. EPA acknowledges that surface air a nd soil gas monitoring may not be suitable in all settings as a method to ensure USDW protection. However, EP A does not believe that this should entirely preclude their use. The decision to use surf ace monitoring and the se lection of monitoring methods will be site-specific (e.g., may be influenced by geology, injection depth, and operational conditions) and must be based on potential risks to USDW s within the AoR.

The final rule at §146.90(h) retains the allowance for surface air and soil gas monitoring at the

discretion of the Director as a means of identif ying leaks that may pose a risk to USDWs and informing emergency notification of a Class VI ow ner or operator and UIC Director in the event of a USDW endangerment, pursuant to requirements at §146.91(c).

Letter ID: 0211 Comment ID: 22782 Letter Lines: 853 to 898

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

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

Comment: G. Post-Injection Site Care Responsibility

The proposed rule contemplates a long pos t-operational period of observation and "site care" prior to closure. The requirements contemplated -- including a presumptive 50-year post-in jection monitoring period -- are unwarranted and completely unprecedented in the UIC program . Not even hazardous waste injection wells -- which generally operate subject to a demonstration that waste will be contained for at least ten thousand year s -- are subject to such burdensome post-injection requirements.

Long term protection of USDWs is ensu red up-front, primarily through proper siting as confirmed through the technical evaluation that occurs in the permitting process. Proper well construc tion, operating, monitoring and testing provide assurance against pr oblems during the operationa l life of an injection well, but siting doesn’t change, and proper siting must be ensure d at the start. Once injection operations cease, there shoul d generally be no need to do more than monitor pressure decay in the inject ion zone and ensure proper plugging of the injection well. This approach is su fficient for the injection of hazardous waste, and it certainly should be suffi cient for the injection of CO2. The premise that careful siting and AOR eval uation are not enough -- that actual monitoring for decades after the cessation of injection is needed -- is foreign to the UIC program and inconsistent w ith the long and thoroughly-documented success of UIC regulation in the United States.

There is certainly no justification for a presumptive 50-year minimum timeframe for post-injection site care, and such a requirement would likely kill-off

41commercial investment in geo-sequestration projects. It does not help that the proposed rule provides a mechanism for shortening the presumptive 50-year requirement, because the ability to shor ten the post-injection site care period would depend on the apparently unlimited di scretion of the Director and could not be assessed in any meaningful wa y before injection operations near completion. Moreover, the possibility of a shorter post-injection site care period is balanced by the possibility that the Director may seek to impose an even longer post-injectio n site care period. The bu rdens and regulatory uncertainties of an extended post-injec tion site care requi rement cannot be justified, especially in the context of a regulatory program that requires a "non-endangerment" demonstration befo re injection can even commence.

Recommendation:

1. EPA should operate from the premise that the UIC program is preventive in

nature.

2. Release from post-injection site care should be determined not by a fixed period of time but rather a performance- based standard that is designed to ensure protection of USDW’s.

Individual Response: EPA agrees that there will be circumst ances 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 ru le offers owners or operators flexibility regard ing the duration of the PISC timeframe by: (1) allowing the Direct or discretion to shorten or lengthen the PISC timeframe during the post-injecti on period based on site-specific da ta, 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 is necessary in mo st cases. A 50 year post-injection site care timeframe represents a reasonabl e and protective monitoring peri od for most GS projects and available data, including data submitted by commenters, do not support a different default

timeframe. This determination is based on a revi ew of research studies, industry reports, and existing environmental programs, and evaluation of public comments.

EPA agrees that proper site characterization, well construc tion, and operation are important components of ensuring that USDWs are protecte d. However, EPA disagrees that this is a substitute for post-injection site care. EPA believes that extensive post-injection monitoring is necessary to protect USDW s from endangerment.

EPA disagrees that the rule affords ¿unlimited di scretion¿ to the Director to lengthen the postinjection site care timeframe. Becau se of the variety of site-speci fic circumstances at GS sites, EPA believes that Directors, in consultation w ith operators, will be in the best position to

42determine whether additional post-injection site care monitoring is needed (or whether the timeframe may be shortened), ba sed on the circumstances of a pa rticular project. EPA expects

this decision to be made based on relevant s ite data, including information at §146.93(c)(2), to determine the appropriateness of an alternative post-injection site care time frame if applicable, and in consultation with all potentially impacted parties.

EPA disagrees that a post-injection site care timeframe of 50 years is excessive for most Class VI wells. EPA proposed a default post-injection site care timeframe of 50 year s based on a review of research studies, industry re ports, and existing environmenta l programs. This analysis was included in an EPA-prepared background document that is available in the federal docket, titled Computational Modeling of Unde rground Injection of Carbon Dioxide for Determination of Area-of-Review and Potential Risk to Undergro und Sources of Drinking Water. EPA assessed

various default timeframes based on additional re view of research stud ies and evaluation of public comments. While numerous commenters s uggested that EPA shorten the monitoring timeframe, none of the commenters provided suff icient data or other evidence to warrant a change in the proposed timeframe. While the 10 - or 30-year timeframe suggested by some of these commenters may be within the timeframe s uggested in some studies, EPA believes that the potential risks of endangering USDWs will likel y not decline within these timeframes and available data, including data submitted by commenters, do not support a different default timeframe. However, EPA recognizes that alte rnative timeframes may be appropriate under limited, specific circumstances, which is why EPA is providing the Director discretion to approve an alternative post-inj ection site care timeframe as l ong as the owner or operator can meet the requirements provided 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 could plug injection and monito ring wells; demonstrate the appropriateness of an alternative post-inject ion site care time frame; perform post-injection monitoring; demonstrate non endangerment; and perf orm site closure activities. This guidance will be available at http://water.epa.gov/t ype/groundwater/uic/wells_sequestration.cfm.

Letter ID: 0211 Comment ID: 22783 Letter Lines: 900 to 916

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

4344 Comment: H. Financial Assurance

SEPCo supports EPA’s flexible approach on financial assurance methods. It would be a mistake to impose any regulatory rest rictions that woul d preclude the use of particular types of financial assuran ce or particular instruments, regardless of whether those are currently used for ot her classes of injection 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 financia l markets gain more experience with geologic sequestration projects. EPA is wi se to avoid any artif icial constraints on the development of potentially accep table means of achieving financial

assurance.

Recommendation:

Recommend that this approach be retained in the final rule.

Individual Response: As described above, owners or opera tors may choose from a variety of

financial instruments to meet their financial responsibility obligations , provided the Director determines that the operator's proposed financial responsibility demonstration is adequate to pay for each activity for which financial responsibilit y must be demonstrated, including corrective action on wells in the AoR, injection well pluggin g, PISC and site closur e, and emergency and remedial response.