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) appreciates this opportunity to provide 

comment to the Environmental Protection Agency (EPA) on its 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 appropriate regulations governing CO2 

injection for purposes of GS. SEPCo agrees that GS is an important option for the 

reduction of CO2 emissions, that the UIC program provides an appropriate framework for 

the regulation of CO2 injection, and that UIC regulations specifically tailored to CO2 

injection could play a vital role in facilitating the development and implementation of GS 

projects while ensuring that appropriate environmental safeguards are in place. 

C. As EPA has correctly recognized, it is critical that any UIC program regulation addressing 

GS be designed to achieve two goals. First, such a rule should ensure that CO2 injection is 

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

such a rule should effectively facilitate and encourage GS as a means to address climate 

change through the reduction of CO2 emissions to the atmosphere. 

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

that is protective of human health and the environment. Indeed there has been a long 

history of successful injection well operation in the United States, and multiple studies have 

confirmed that the UIC program has been remarkably effective in ensuring protection of 

human health and the environment. While GS projects are likely to be large in scale, it is 

important to recognize that the injection of CO2 is nothing new. To the contrary, CO2 has 

been injected for purposes of enhanced oil and gas recovery (EOR/EGR) for more than 

thirty-five years, and the UIC program already regulates more than 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 environment. 
2

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

the use of GS to reduce CO2 emissions – we ask that EPA utilize more of the successful 

practices from the experience detailed above in its final decision 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 significantly to increase the flexibility 

of the requirements for CO2 injection and reduce the unnecessary regulatory burdens the 

proposed rule would impose. SEPCo respectfully recommends EPA 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 listed 

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 need to reevaluate the 

AOR. Where monitoring results remain consistent with modeling results, a 

requirement to reevaluate the AOR should not be required. 

• Well Construction Standards:

• The Class VI requirements addressing issues such as well construction and 

mechanical integrity testing should be no different than the Class II requirements.

• 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 – and can be mitigated by – measures implemented at 

closure.

• Site Characterization/Evaluation: 
3

 EPA should seek to develop clear performance standards as detailed in the 

American Petroleum Institute’s submission regarding site characterization. 

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 characteristics of a 

project such as project size, geologic factors, and relative risk 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. Specifically, 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 waste 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 transport and storage, 

EPA should work to dispel concerns that geologic sequestration could be 

encumbered with those requirements except possibly through the commingling of 

a captured CO2 stream with an actual waste stream. 

III. General Comments

A. SEPCo Supports Development of Appropriate UIC Program Regulations for 

GS. 

SEPCo 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 existing CO2 

injection wells – and enjoys an enviable and extensively documented record of success. The 
4

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

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

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

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

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

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

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

The UIC program currently provides regulations that are being successfully applied to CO2 

injection. Nevertheless, SEPCo agrees with EPA in the need to develop regulations more 

specifically designed to address CO2 injection in the GS context. Our primary recommendation is 

that such regulations build on relevant UIC program experience, including experience with CO2 

injection, and should be tailored to address the particular needs for this category of injection activity: 

both the need to protect USDWs and the need to facilitate use of GS as a technology for reducing 

CO2 emissions. In developing such regulations, it is important that EPA maintain a flexible, 

performance-based approach that allows regulators to tailor specific permit requirements as 

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

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

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

“Class VI” Regulations to Address Other CO2 Injection Wells Used for GS. 

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

Under the proposed rule, Class II CO2 injection 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 enhanced oil or gas recovery (“EOR/EGR”) has been successfully regulated as Class II 

injection for decades, and there is nothing to justify any disruption of the existing regulatory regime 

for the thousands of injection wells already in use in these operations. For other GS injection 

projects, Class VI regulations would permit a more structured basis for regulation than the Class V 

regulations. 

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

to Protect USDWs.

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

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

USDWs. 73 Fed. Reg. at 43497-98. Unfortunately, the proposed rule seems to proceed from the 

premise that the strictest 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 vast 

knowledge and experience 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. 
5

As the proposed rule recognizes, CO2 injection operations have been conducted pursuant to the 

Class II regulations for many years, and experience with thousands of wells injecting hundreds of 

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

are adequate to protect USDWs This is certainly true with respect to the basic construction, 

operating, monitoring, and mechanical integrity testing requirements for injection wells; 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 requirements are far more 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 after oil or gas production has ceased. 

Rather than resembling the Class II requirements, the proposed Class VI requirements are as 

stringent as those for hazardous waste injection in most respects. Indeed, many of the construction, 

mechanical integrity, 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 legitimately related to concerns about the 

mobility of CO2 or the anticipated scale of GS operations, many – as discussed in Part III of these 

comments – are not. 

Recommendation:

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

testing should be no different than the Class II requirements.

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

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

stringent regulatory requirements – particularly requirements for multiple layers of protections 

addressing the same basic risk – inherently 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 infrastructure, and believes strongly in the need to ensure that the public has accurate 

information to inform it. To facilitate the public’s appreciation of the merits of GS, SEPCo urges 

EPA to ensure that it does not overstate the risks associated with CO2 injection or understate the 

justified confidence with which many potential issues and concerns can be addressed Similarly, 

SEPCo urges EPA to avoid the imposition of regulatory requirements 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 accurately reflect the magnitude of actual 

risks and to ensure that the requirements imposed are necessary for the protection of USDWs. 

SEPCo believes that permanent storage of CO2 can be accomplished safely and without harm to the 

environment by utilizing the appropriate knowledge base, detailed site-specific information, 
6

technical expertise, and sound management practices. It is therefore important that EPA send 

accurate messages about the nature of CO2 and the actual magnitude of the risks associated with GS. 

It is also critical that EPA strike an appropriate balance by addressing the risks associated with GS 

without creating a regime that effectively hinders or deters use of this key technology for reduction 

of 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 reduction of greenhouse gas emissions – could prove 

environmentally counterproductive, given potential operators inability to deploy GS projects.

E. Lowermost USDW Restriction

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

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

the protection of USDWs and would remove a vast number of viable formations1/ from 

consideration for GS. Industry has shown that it can operate CO2 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 has a USDW below the injection zone. 

Moreover, under the proposed rule, there are other measures that would provide real assurance of 

formation integrity and require operators to demonstrate that their project will not endanger 

USDWs, making the lowermost USDW restriction unnecessary.

Recommendation:

Injection above the lowest USDW should be allowed but the operator 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 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 entry 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 their edits to §146.93(b)(3).) Clear guidelines 

also need to be established regarding when operators have met the 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 promising CO2 storage option . . ..” 73 Fed. Reg at 43500. 
7

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. 

G. RCRA

SEPCO agrees with the concept that Class VI wells should not be injecting hazardous wastes but is 

proposing some modifications to EPA’s definition of CO2 stream in the rule. The modifications 

reflect the fact that the source of CO2 should not be a factor in the context of defining the CO2 

stream. The rule applies to the injection of CO2 and should not address the origins of the materials 

since that is beyond the scope of this regulation. The original text would have precluded injection of 

CO2 from some sources. 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 should not be arbitrarily prohibited; however, it is recognized that the 

presence of those impurities at sufficient concentrations may trigger the applicability of other 

statutory limits or requirements. Determining the type and levels of impurities in the CO2 stream is 

– absent a compelling public or environmental health risk – best left to contractual negotiations 

between partners in a CCS value chain as opposed to an arbitrary regulatory determination. The 

contracting parties are best able to evaluate the types of impurities, their compatibility with the 

reservoir and equipment, and determine the acceptable levels of those impurities in the stored CO2. 

To the extent that there is an overriding public interest in limiting the type or level of contaminants, 

principles of cost-effectiveness and risk-management should guide the decision making process. 

With specific respect to RCRA, SEPCo is concerned that EPA’s brief discussion of a supposed 

potential for injected CO2 streams to be characterized as hazardous waste (or some type of 

hazardous release) could have a significant chilling effect on the deployment of CO2 capture and 

sequestration technologies. Based on the work of our engineers and scientists with capture 

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

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

application of RCRA. In addition, EPA’s Proposal suggests that injected CO2 may be considered 

hazardous waste for RCRA purposes, and defines “carbon dioxide stream” to exclude hazardous 

waste. 73 Fed. Reg. at 43503. The premise appears to be that CO2 is solid waste, and that a waste 

determination for such solid waste would turn on the specific composition of the CO2 in question. 

Id. Based on this premise, the preamble suggests, “EPA cannot make a categorical determination as 

to whether injected CO2 is hazardous waste under RCRA.” Id. 

Rationale: 

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

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

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

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

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

cannot be considered hazardous waste for RCRA purposes. 
8

The RCRA definition of solid waste is limited to “solid, liquid, semi-solid, or contained gaseous 

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

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

of the statute makes sense, because RCRA is plainly aimed at the kind of material that could end up 

being dumped into a landfill. Uncontained supercritical CO2 is not such a material. Instead, the 

physical properties of supercritical CO2 are such that it would immediately vaporize – becoming an 

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

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

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

largely on test methods that are inapplicable to materials such as supercritical CO2. In particular, the 

toxicity characteristic depends on test methods that can only be applied to materials that are solids 

or liquids at standard temperatures and pressures. This is unsurprising, because the toxicity 

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

scenario, a scenario that – as already discussed – is inherently inapplicable to supercritical CO2. 

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

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

CO2 is not “solid waste” and is not subject to RCRA waste determination requirements. 

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

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

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

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

Recommendations: 

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

RCRA status of CO2. 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 concerns that geologic sequestration could be encumbered with those 

requirements except possibly through the commingling of a captured CO2 stream with an 

actual waste stream. 

IV. Comments Regarding Proposed Class VI Requirements

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 with sufficient permeability, porosity, thickness and 

lateral extent and a low-permeability confining zone with sufficient thickness and lateral extent to 
9

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 for codification at 40 

C.F.R. 146.83(a). Unfortunately, the preamble goes on to suggest the need for 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 Administrator 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 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 ensure 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 an elaborate evaluation of site 

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

however, seismicity and geochemical compatibility are issues that are easily addressed in the GS 

context, and requirements for unnecessarily elaborate analysis would serve only to burden and 

impede the development of GS projects. 

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

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

injection pressure limitations. Similarly, geologic compatibility – while it can present issues in some 

contexts – is unlikely to present any serious problems in the GS context. These conclusions are 

confirmed by decades of experience with 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 extremely 

corrosive hazardous wastes demonstrates – cannot reasonably be expected to cause any breach of 

containment that would endanger a USDW. The proposed rule expresses specific concern about 

geochemical reactions that could alter the composition of the injected CO2 stream – particularly 

through the mobilization of contaminants that occur naturally in the injection zone – but such 

concerns are immaterial because the specific composition of the CO2 stream matters little as long as 

the CO2 remains confined. Another theoretical concern relates to the potential for geochemical 

changes to contribute to the plugging of pore spaces in the injection 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 subsequent 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 

permeability in the injection zone, thereby reducing the efficiency (but not the safety) of the 

injection operation. 
10

In short, geochemical changes related to CO2 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 geochemical data from monitoring wells are 

needed to evaluate the impact” of potential geochemical changes related to CO2 injection. 

Recommendation:

Remove requirements for detailed analysis of potential chemical 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 require, or allow the Administrator 

discretion to require, additional 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 protection of USDWs, a requirement 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 definition, 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 confining and containment zones above the 

injection zone would be unprecedented. No such requirement exists in the UIC program, even in 

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

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

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

be warranted on the merits of the actual risk. 

Recommendation:

Require 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 

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 of the appropriate area of review 

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

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

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

by penetrations such as abandoned boreholes. The use of such modeling is already well established 

in the context of oil and gas exploration and production and has been used in the UIC program for 

“no-migration” petitions for hazardous waste injection. Similar modeling can reasonably be adopted 

for use in the GS context as well. 
11

1. AOR Definition

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

be impacted by the injection activity.” 72 Fed. Reg. at 43535 (proposed 40 C.F.R. 146.81(d)). The 

definition goes on to suggest that the AOR is to be “based on computation modeling 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 

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 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 plume – that matters, 

and modeling of chemical changes would be unnecessary. Similarly, the preamble suggests that the 

”most sophisticated” and most “accurate” modeling should be preferred 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 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., “may be impacted 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. 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 

corrective 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 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 reevaluate the AOR should not be required. 

C. Injection Well Construction Requirements

1. Well Design
12

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

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

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

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

well construction requirements resembling those for Class I hazardous waste injection wells. The 

proposed rule specifically cites the buoyancy of CO2 as the justification for these requirements. See 

73 Fed. Reg. at 43509. 

SEPCo argues that the buoyancy of CO2 in no way justifies the additional construction 

requirements proposed. The reason for this is straightforward: by far the greatest driving force for 

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

caused by fluid injection during the operation of the injection well. The magnitude of this pressure 

influence is at its maximum at the point of injection, and – within the injection interval – it generally 

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

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

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

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

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

latter insignificant. 

In short, buoyancy can be significant as a driver for lateral fluid movement, but provides a relatively 

weak driver for vertical fluid flow that – at the point of injection – 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 injection wells. 

SEPCo nevertheless supports the requirements for a surface casing cemented to the surface, for 

injection through a tubing and packer, and for a well design that permits continuous monitoring of a 

pressurized annulus. The requirement SEPCo finds objectionable is that for continuous cement 

along the entire long-string 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 

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

appropriately determined in the permitting process. 

Recommendation:

Utilize Class II well construction standards for the Class VI program. The proposed design 

standard mandating continuous cement for the long string casing should be deleted as unnecessary 

and unduly burdensome. 

2. Materials of Construction

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

degradation-resistant construction materials such as acid-resistant cement and a corrosion-resistant 

casing. 73 Fed. Reg. at 43510. These requirements are based on the premise that CO2 is corrosive 
13

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

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

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

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

streams would often (if not generally) be “dry”(i.e., dehydrated) and therefore non-corrosive. Once 

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

creating carbonic acid. However, an injection well would inject CO2 far more rapidly than the CO2 

could mix with water, creating a CO2 plume that would immediately displace water away from the 

point of injection, creating 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 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 – there is no basis to suggest that injected 

CO2 is corrosive or that injection wells must be designed and constructed to resist a particularly 

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). However – 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-resistant construction or the occurrence of corrosionrelated problems. 

Well construction requirements under the UIC program generally require that operational conditions 

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

these general requirements have served well. Thus, while there may be some Class VI CO2 injection 

scenarios in which corrosion-resistant materials may be required, there is no technical basis for any 

general presumption that they are necessary or should be required. 

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 – 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 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 pressure during injection does not initiate new 

fractures or propagate existing fractures in the confining zone adjacent to the 
14

USDWs. In no case shall injection pressure cause the movement 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 regulatory 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 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 restrictive requirements designed not just to prevent 

endangerment of USDWs, but to ensure that there is no fracturing 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 sequestration, 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 wells should be based on the existing Class II 

requirements, modified slightly to address the possibility of Class VI injection occurring above the 

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 pressure during injection does not initiate new 

fractures or propagate existing fractures in the confining zone. In no case shall 

injection pressure cause movement of injection or formation fluids that endangers an 

underground source of drinking water. 

2. Down-Hole Shut-Off Valves

EPA proposes to require automatic shut-off valves down hole 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 injection wells are not required to have downhole automatic shut-off valves, and there is no basis to suggest that CO2

 injection entails higher risks 

warranting costly additional safety measures that would interfere with monitoring and potentially 

with any necessary well remediation. 

3. Corrosion Monitoring

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

that carbon sequestration wells will typically or even often be injecting corrosive fluids. A general 

requirement for corrosion monitoring is therefore unnecessary and inappropriate. 

E. Mechanical Integrity Testing (MIT) Requirements
15

The proposed rule suggests, “MIT requirements for GS wells should be tailored to address the 

unique properties of CO2, specifically its buoyancy and potential corrosivity.” 73 Fed. Reg. at 

43513. As previously discussed, however, the buoyancy of CO2 is a relatively trivial factor in 

relation to the cone of influence created by injection pressure during injection, a factor that makes 

buoyancy virtually irrelevant as a driving force for upward migration through the injection well 

borehole during the operational life of a GS well. Accordingly, there is no basis to suggest that the 

buoyancy of CO2 is relevant to be considered in establishing mechanical integrity testing 

requirements for GS wells. Similarly – as also previously discussed – CO2 is not corrosive and 

cannot be expected to cause corrosion problems for the injection 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 not 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 for CO2 injection in the EOR/EGR 

context, and there is no reason why they should not be sufficient in the GS context as well. 

F. Testing and Monitoring Requirements

The preamble to the proposed rule indicates, “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 regulatory 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 injection demonstrates that plume and pressure 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 modeling demonstrations that can and 

should be relied upon to support determinations that injected CO2 will not endanger USDWs. 

The suggestion that it makes sense to monitor the movement of injected CO2 in the subsurface also 

does not consider the nature and utility 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 the GS context are 

excessive and unjustified. 

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 

concerning such interactions should rarely if ever be relevant from a regulatory standpoint. In 

particular, USDWs are generally protected by ensuring that injected 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 that could actually compromise 

containment cannot reasonably be expected in the absence of truly unusual circumstances. 
16

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

unreasonable. 

1. Monitoring CO2 Movement and Reservoir Pressure

The preamble to the proposed rule specifically states that the “[m]onitoring of subsurface 

geochemistry and the position of the CO2 plume and pressure front are necessary to verify 

predictions of plume movement, provide inputs for modeling, identify needed corrective actions, 

and target geochemical and surface monitoring activities.” 73 Fed. Reg. at 43514. Again, this is an 

assertion that cannot be reconciled with experience with Class I hazardous waste injection, where 

such monitoring has never been considered necessary and is not required. 

a. Monitor Wells

Monitor wells reaching the deep subsurface are problematic in a variety of respects. They are 

expensive to install, create potential pathways for vertical fluid migration, and – in the deep 

subsurface where natural fluid movement may be very slow or effectively non-existent – they have 

little potential to provide more than an isolated “point 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 the 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 benefit from monitoring wells 

designed to detect potential leakage from an injection zone, because the ability to detect such leakage 

is at best a hit-or-miss (if not a needle in a haystack) proposition. Monitor wells also have built-in 

confounding factors that include both the potential for well construction to impact fluid quality in 

the target sampling interval and the fact that sampling may itself cause fluid movement that might 

not otherwise occur. Because pressure fronts extend much further than injected fluid plume fronts 

during injection, pressure monitoring is more likely to be useful than fluid sampling, but costs would 

still be very high and the ability to detect relevant changes would still be 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 

Administrator to address particular circumstances at the site. See 52 Fed. Reg. 32446 at 32463-64 

(August 27, 1987), 53 Fed. Reg. 28118 at 28141, 28144-45 (July 26, 1988). Experience with 

hazardous waste injection does not commend the use of monitor wells even in that context, and 

there is no justification to impose 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 suggests that it may be possible to use remote 

geophysical techniques for “plume tracking.” 73 Fed. Reg. at 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 general, the technologies available would be 

very expensive to employ on the scale required, and provide inferential data that is subject to 

considerable interpretation. Such techniques are unsuitable 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 be used for “plume tracking” to “verify” 

the results of modeling is optimistic at best, and creates unrealistic expectations for the technologies 

involved. In fact, the use of such techniques may do more to amplify 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 ensure that injected CO2 streams 

remain confined in the subsurface and do not endanger underground sources 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 confounding factors. Worst of all, such 

monitoring would be aimed at leakage of CO2 all the way to the surface, which – in the case of any 

properly-permitted GS project – would by definition be an extraordinarily low probability scenario. 

Recommendation:

Surface Air and Soil Gas Monitoring should not be imposed, nor should regulators have discretion 

to impose them. The potential for possible leakage pathways should be demonstrated and managed 

during the permitting process. 

G. Post-Injection Site Care Responsibility

The proposed rule contemplates a long post-operational period of observation and “site care” prior 

to closure. The requirements contemplated – including a presumptive 50-year post-injection 

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 years – are subject to such burdensome post-injection 

requirements. 

Long term protection of USDWs is ensured up-front, primarily through proper siting as confirmed 

through the technical evaluation that occurs in the permitting process. Proper well construction, 

operating, monitoring and testing provide assurance against problems during the operational life of 

an injection well, but siting doesn’t change, and proper siting must be ensured at the start. Once 

injection operations cease, there should generally be no need 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 certainly should be sufficient for the injection 

of CO2. The premise that careful siting and AOR evaluation are not enough – that actual 

monitoring for decades after the cessation of injection is needed – is foreign to the UIC program 

and inconsistent with the long and thoroughly-documented success of UIC regulation in the United 

States. 
18

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 commercial 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 shorten the post-injection site care period 

would depend on the apparently unlimited discretion of the Director and could not be assessed in 

any meaningful way 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-injection site care period. The burdens and regulatory uncertainties of 

an extended post-injection site care requirement cannot be justified, especially in the context of a 

regulatory program that requires a “non-endangerment” demonstration 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 determined not by a fixed period of time but 

rather a performance-based standard that is designed to ensure protection of USDW’s. 

H. Financial Assurance

SEPCo supports EPA’s flexible approach on financial assurance methods. It would be a mistake to 

impose any regulatory restrictions that would preclude the use of particular types of financial 

assurance or particular instruments, regardless of whether those are currently used for other classes 

of injection wells or in other EPA programs. Allowing for flexibility recognizes that operators are 

likely to use combinations of approaches and instruments to meet these requirements and that these 

combinations may change significantly over time as operators, program Directors and the financial 

markets gain more experience with geologic sequestration projects. EPA is wise to avoid any 

artificial constraints on the development of potentially acceptable 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 Under the Underground Injection 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. SEPCo agrees that GS is an important 

option for the reduction of CO2 emissions, that the UIC program provides an 

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

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

facilitating the development and implementation of GS projects while ensuring 

that appropriate environmental safeguards are in place. 

C. As EPA has correctly recognized, it is critical that any UIC program 

regulation addressing GS be designed to achieve two goals. First, such a rule 

should ensure that CO2 injection is conducted in a manner that is protective of 

human health and the environment. Second, such a rule should effectively 

facilitate and encourage GS as a means to address climate change through the 

reduction of CO2 emissions to the atmosphere. 

D. Fortunately, there is abundant evidence that CO2 injection can be 

accomplished in a manner that is protective of human health and the environment. 

Indeed there has been a long history of successful injection well operation in 

the United States, and multiple studies have confirmed that the UIC program has 

been remarkably effective in ensuring protection of human health and the 

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

to recognize that the injection of CO2 is nothing new. To the contrary, CO2 has 

been injected for purposes of enhanced oil and gas recovery (EOR/EGR) for more 

than thirty-five years, and the UIC program already regulates more than 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 environment. 

1
E. To achieve its goals for this rulemaking - to address the risks of CO2 

injection and promote the use of GS to reduce CO2 emissions - we ask that EPA 

utilize more of the successful practices from the experience detailed above in 

its final decision on each of the requirements it has proposed for CO2 

injection. SEPCo believes, as further detailed in these comments 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 framework for regulating injection 

of CO2 for GS and adds that the GS regulation tailors the UIC requirements to address the 

unique issues associated with large-scale GS including large injection volumes, the relative 

buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in 

captured CO2, and its mobility within subsurface geologic formations. 

EPA recognizes that the oil and gas industry has decades of experience 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 certain percentage of the 

CO2 is trapped in the receiving formation. 

Also, since field experience and well construction, injection, and monitoring 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 continues 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 (performance-based standards) 

Comment: injection. SEPCo believes, as further detailed in these comments that the 

proposed requirements should be streamlined significantly to increase the 

flexibility of the requirements for CO2 injection and reduce the unnecessary 

regulatory burdens the proposed rule would impose. SEPCo respectfully recommends 

EPA modify its proposed regulatory 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 flexible approach, where operators of GS projects 

would develop and implement site-specific plans for delineating the AoR, testing and monitoring 

the site, performing corrective action, and post-injection site care. EPA believes that the plans—

which would be reviewed and approved by the Director and periodically updated throughout the 

life of the project—promote an ongoing dialogue between the operator and the Director that will 

encourage use of the most appropriate technologies for a particular project. 

2
Letter 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 limited circumstances where injection 

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

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

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

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

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

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

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

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

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

below the injection zone. 

EPA believes that proper siting, monitoring, and containment capacity are critical elements of 

Class VI injection for GS. However, the Agency also believes that injection 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 below the injection zone. 

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

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

Comment: - 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 need to reevaluate the 

AOR. Where monitoring results remain consistent with modeling results, a 

requirement to reevaluate the AOR should not be required. 

Individual Response: EPA thanks the commenter for their input 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 determining when AoR reevaluations are 

appropriate, and expects that the owner or operator's and Director's combined knowledge of the 

local geologic conditions will be a critical element in developing plans that protect USDWs from 

3
endangerment. 

EPA is developing guidance on AoR and corrective action at GS Class VI sites 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 AoR delineation, how to apply computational modeling 

to delineate the AoR, performing corrective action at GS sites, and, when appropriate, 

completing AoR reevaluations. The guidance will be available on EPA's web site, at 

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

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 issues 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 Class II wells and Class VI wells indicate that the Class II 

requirements are not sufficient to address the differences and that Class VI MIT requirements 

are, therefore, appropriate. For example, the volume of CO2 anticipated to be injected in Class 

VI wells is significantly greater than for Class II wells. Also, reservoir pressure conditions will 

be different with ER production (extraction) serving to reduce reservoir pressure for Class II 

operations while Class VI injection operations will have no comparable de-pressuring activities. 

For these reasons, EPA believes that injection of CO2 for GS projects differs 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 additional information, please see the discussion of 

MITs in the final rule preamble. 

EPA is using an adaptive approach to regulating GS. The Agency plans to collect and review 

data every six years on early GS projects, including MIT data, to determine whether the 

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

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

Letter ID: 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 materials should be selected based on planned 

operating life of the injection well, not the ultimate duration of the GS 

4
program. The potential for longer-term exposure of well components after 

injection has ceased will depend upon - and can be mitigated by - measures 

implemented at closure. 

Individual Response: EPA disagrees that the casing, cement or other materials should only be 

designed for the period of the injection process, rather than the life of the sequestration project. 

GS projects are anticipated to have long life spans in comparison to other types of deep injection 

wells. Not only must Class VI wells be able to function safely and properly over the lifespan of 

the GS project, but they must be constructed such that USDWs remain protected after well 

plugging. The requirements at §146.86 will ensure that the well can maintain integrity 

throughout the proposed life span of the project, including after the injection well is plugged and 

through the post-injection site care period and beyond. While the risk profile of a GS site will 

decrease following cessation of injection, EPA believes that Class VI wells must be designed to 

protect USDWs from endangerment for the life of the project. Furthermore, rigorous casing and 

cementing help ensure that the Class VI well will not serve as a conduit for movement of fluids 

associated with future injection operations. 

Letter ID: 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 should seek to develop clear performance 

standards as detailed in the American Petroleum Institute’s submission regarding 

site characterization. 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. 

Individual Response: EPA agrees with the commenter on the importance of proper site 

characterization, and clarifies that the purpose of the GS regulation is to ensure that injection of 

CO2 for GS is conducted in a manner that is protective of USDWs based on an evaluation of 

site-specific information. This includes appropriate site characterization and identification of 

geologic formations that are amenable to injection of potentially large volumes of CO2 for longterm storage. The regulation provides flexibility to owners or operators to select appropriate sites 

and target formations (under §146.82), well construction specifics (under 146.86), and injection 

procedures provided the owner or operator can demonstrate that the injection and storage will not 

endanger USDWs and that minimum requirements for the site are met. 

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 owners or operators regarding characterizing the regional geology 

and hydrogeology of a proposed GS site as well as performing the necessary geochemical, 

geomechanical, and geophysical analyses of the injection and confining zone. EPA expects that 

this guidance will assist permit writers in making an objective decision about requiring 

additional confining layers. The guidance can be found on EPA’s website at 

5
http://water.epa.gov/type/groundwater/uic/wells_sequestration.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: Criteria 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, geologic factors, 

and relative risk 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. 

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 requirements in the final GS rule incorporate 

a combination of a fixed timeframe and a performance standard approach. The final GS rule 

offer owners or operators flexibility regarding the duration of the PISC timeframe by: (1) 

allowing the Director discretion to shorten or lengthen the PISC 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 Class VI well owner or operator to demonstrate, 

during the permitting process based on substantial data, that an alternative PISC timeframe may 

be appropriate if it ensures non-endangerment of USDWs pursuant to requirements at 

§146.93(c). 

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

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

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

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

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

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

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

impacts. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells; perform 

post-injection monitoring; demonstrate the appropriateness of an alternative post-injection site 

care time frame; demonstrate non-endangerment; and perform site closure activities. The 

guidance will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

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

6
Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: - 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. 

Individual Response: EPA agrees about the need for flexibility, which is why owners or 

operators 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 protect USDWs from endangerment by paying for 

each activity for which financial responsibility must be demonstrated, including corrective action 

on wells in the AoR, injection well plugging, PISC and site closure, and emergency and remedial 

response. 

Owners or operators may select different instruments for specific project activities. EPA also 

anticipates that the availability of third-party GS financial instruments will grow in response to 

demand for such instruments by 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 issues (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 CO2 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 decided to initiate a separate proposed rulemaking 

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

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

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

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

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

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

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

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

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

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

7
Comment 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 concerns that geologic sequestration could be 

encumbered with those requirements except possibly through the commingling of a 

captured CO2 stream with an actual waste stream. 

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 scope 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 applicability of the RCRA regulations and statute to 

CO2 streams that are geologically sequestered under the final Class VI UIC well requirements. 

As a result, EPA has decided to initiate a separate proposed rulemaking specifically to examine 

the issue of RCRA applicability to CO2 streams being geologically sequestered, including the 

possible option of a conditional exemption from the RCRA requirements for CO2 GS in Class 

VI wells. EPA will consider these comments as part of its development of that proposal. The 

Agency will consider issues particular to RCRA in the context of that separate rulemaking, and 

recommends that the commenter read that proposed rule when it is published. The Agency notes 

that commenters who wish to submit comments on the RCRA proposal will need to do so during 

the comment period for that rule. Finally, EPA also notes that the final GS rule, which adds new 

regulations for Class VI wells under the Safe Drinking Water Act (SDWA), is not making any 

changes to the RCRA regulations. 

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

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

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

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

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

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

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

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

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

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

minerals. 

Letter ID: 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 Appropriate UIC Program Regulations for GS. 

8
SEPCo 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 existing CO2 injection wells - and enjoys an 

enviable and extensively documented record of success. The program has in many 

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

long history of regulatory and technical discourse among agencies and regulators 

armed with considerable practical experience and exceptional technical 

expertise. While the UIC program is focused on the protection of "underground 

sources of drinking water" (USDWs), this seemingly narrow objective is narrow in 

name only. In fact, the measures the UIC program relies upon to protect USDWs - 

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

subsurface - are by nature sufficient to ensure protection of human health and 

the environment. 

The UIC program currently provides regulations that are being successfully 

applied to CO2 injection. Nevertheless, SEPCo agrees with EPA in the need to 

develop regulations more specifically designed to address CO2 injection in the 

GS context. Our primary recommendation is that such regulations build on 

relevant UIC program experience, including experience with CO2 injection, and 

should be tailored to address the particular needs for this category of 

injection activity: both the need to protect USDWs and the need to facilitate 

use of GS as a technology for reducing CO2 emissions. 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 necessary to enable the use of GS as a climate 

change mitigation technology in a manner that 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 (performance-based standards) 

Comment: use of GS as a technology for reducing CO2 emissions. In developing such 

regulations, it is important that EPA maintain a flexible, performance-based 

approach that allows regulators to tailor specific permit requirements as 

appropriate based on the broad range of injection sites and practices that may 

be encountered in the GS context and on the body of knowledge and experience 

that will be gained not only from pilot and demonstration projects, but from the 

initial deployment of commercial scale 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 flexible approach, where operators of GS projects 

would develop and implement site-specific plans for delineating the AoR, testing and monitoring 

the site, performing corrective action, and post-injection site care. EPA believes that the plans—

which would be reviewed and approved by the Director and periodically updated throughout the 

9
life of the project—promote an ongoing dialogue between the operator and the Director that will 

encourage use of the most appropriate technologies for a particular project. 

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

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: B. SEPCo Supports Continued Application of the Class II Regulations to CO2 

Injection in the Enhanced Oil or Gas Recovery Context and the Creation of "Class 

VI" Regulations to Address Other CO2 Injection Wells Used for GS. 

CO2 injection wells are currently permitted as Class II or Class V "experimental 

technology: wells. Under the proposed rule, Class II CO2 injection 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 enhanced oil or gas 

recovery ("EOR/EGR") has been successfully regulated as Class II injection for 

decades, and there is nothing to justify any disruption of the existing 

regulatory regime for the thousands of injection wells already in use in these 

operations. For other GS injection projects, Class VI regulations would permit a 

more structured basis for regulation 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 Class II Program. However, the Agency believes 

that the nature and risks of CO2 injection for 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 significantly greater than for EOR operations. Reservoir 

pressure conditions will also be different, with Class VI injection operations involving large 

volumes of CO2 and likely having higher pressures within their storage formations than Class II 

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 actual human health and ecological risks 

associated with GS are relatively remote and can be addressed effectively 

through measures implemented to protect USDWs. 73 Fed. Reg. at 43497-98. 

Unfortunately, the proposed rule seems to proceed from the premise that the 

10
strictest 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 vast knowledge and experience 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 injection operations have been conducted 

pursuant to the Class II regulations for many years, and experience with 

thousands of wells injecting hundreds of millions of tons of CO2 demonstrates 

that the Class II regulations - as applied to CO2 injection - are adequate to 

protect USDWs This is certainly true with respect to the basic construction, 

operating, monitoring, and mechanical integrity testing requirements for 

injection wells; 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 requirements are far more 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 after oil or gas production has ceased. Rather than resembling 

the Class II requirements, the proposed Class VI requirements are as stringent 

as those for hazardous waste injection in most respects. Indeed, many of the 

construction, mechanical integrity, 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 legitimately related to concerns about the 

mobility of CO2 or the anticipated scale of GS operations, many - as discussed 

in Part III of these comments - are not. 

Recommendation: 

The Class VI requirements addressing issues 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, Class II, and Class V experimental 

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

provides for the construction of these wells to be grandfathered per §146.81(c), provided the 

owner or operator can demonstrate to the Director that the wells were engineered and constructed 

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

at §146.86(b) and §146.87(a). 

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR 

requirements) should also be grandfathered. Following re-permitting of the well as Class VI, 

many of the unique factors of GS sites (e.g., increased reservoir pressures associated with large 

11
volumes of stored CO2 and the corrosivity of CO2 in the presence of water) will result in an 

increased risk profile, warranting the specific requirements in the final GS rule. Therefore, 

following re-permitting as Class VI wells, these projects must be subject to the operational, MIT, 

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the 

final GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS 

rule for additional detail on these requirements. 

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

Comment Code: 1680 1.3.8 Don't overstate risk, 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 reasons. First, unnecessary regulatory 

burdens would act as a direct impediment and disincentive to the development of 

GS projects. Less directly, the imposition of unreasonably stringent regulatory 

requirements - particularly requirements for multiple layers of protections 

addressing the same basic risk - inherently 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 infrastructure, and believes strongly in the 

need to ensure that the public has accurate information to inform it. To 

facilitate the public’s appreciation of the merits of GS, SEPCo urges EPA to 

ensure that it does not overstate the risks associated with CO2 injection or 

understate the justified confidence with which many potential issues and 

concerns can be addressed Similarly, SEPCo urges EPA to avoid the imposition of 

regulatory requirements 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 accurately reflect the 

magnitude of actual risks and to ensure that the requirements imposed are 

necessary for the protection of USDWs. 

SEPCo believes that permanent storage of CO2 can be accomplished safely and 

without harm to the environment by utilizing the appropriate knowledge base, 

detailed site-specific information, technical expertise, and sound management 

practices. It is therefore important that EPA send accurate messages about the 

nature of CO2 and the actual magnitude of the risks associated with GS. It is 

also critical that EPA strike an appropriate balance by addressing the risks 

associated with GS without creating a regime that effectively hinders or deters 

use of this key technology for reduction of CO2 emissions to the atmosphere. 

Recommendations: 

12
EPA should consider that overly-burdensome regulation - to the extent it 

effectively impedes or deters use of a "promising technology" for the reduction 

of greenhouse gas emissions - could prove environmentally counterproductive, 

given potential operators inability to deploy GS projects. 

Individual Response: EPA disagrees that the GS regulation overstates the risk of CO2 injection 

or that it is “overly burdensome.” EPA recognizes that injecting large volumes of CO2 for GS 

poses unique challenges that, if not properly managed, could endanger drinking water sources 

and have other adverse impacts. However, with proper site selection, the final, tailored, Class VI 

requirements address the large volumes of CO2 injected, its buoyancy, potential corrosivity in 

the presence of water, and potential impurities in the CO2 stream. In addition, EPA expects the 

tailored permitting, siting, construction, operation, monitoring, and post-injection site care 

requirements in the GS rule to prevent leakage from injection formations and protect USDWs. 

EPA does not believe that the tailored requirements will create a negative public perception of 

GS. The Agency believes that a demonstration to the public that GS projects are meeting the GS 

rule's tailored requirements will likely improve confidence in the project and help address public 

questions and concerns. 

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 injection to injection into formations that 

are below the lowermost underground source of drinking water (USDW). This 

requirement is not necessary for the protection of USDWs and would remove a vast 

number of viable formations(SEE FOOTNOTE 1) from consideration for GS. Industry 

has shown that it can operate CO2 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 has a USDW below the 

injection zone. Moreover, under the proposed rule, there are other measures that 

would provide real assurance of formation integrity and require operators to 

demonstrate that their project will not endanger USDWs, making the lowermost 

USDW restriction unnecessary. 

Recommendation: 

Injection above the lowest USDW should be allowed but the 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. 

13
Individual Response: As described above, EPA acknowledges that there are limited 

circumstances where injection above the lowermost USDW can be performed in a manner that 

protects USDWs from endangerment, as long as appropriate protections are in place. The final 

GS rule at §146.95 establishes a process by which owners or operators can seek a waiver of the 

Class VI injection depth requirements for injection into non-USDW formations above and/or 

between USDWs. It establishes: 1) requirements specifying information that owners or operators 

must submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures 

for public notice of a waiver application and for Director-Regional Administrator 

communication; 3) the waiver issuance process; and, 4) additional requirements that apply to 

owners or operators of Class VI wells granted a waiver of the injection depth requirements to 

ensure USDW protection above and below the injection zone. 

For additional information on the waiver approach, please see the final rule and preamble, as 

well as EPA's responses to comments on the Notice of Data Availability and Request for 

Comment. 

Letter ID: 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 entry into CCS operations. 

Individual Response: EPA disagrees with this comment. In determining the post-injection site 

care-timeframe for the proposed regulation, EPA reviewed industry reports, existing 

environmental programs, and initial GS research studies. EPA provided a synthesis of pertinent 

results from GS modeling studies in the preamble to the proposed regulation. Further explanation 

of this analysis was included in an EPA-prepared background document that is available in the 

federal docket, titled "Computational Modeling of Underground Injection of Carbon Dioxide for 

Determination of Area-of-Review and Potential Risk to Underground Sources of Drinking 

Water." Based on review of these studies, modeling results indicate that the CO2 plume 

stabilization may occur on the timeframe of 10-100 years after the cessation of injection. EPA 

believes that a 50-year default post-injection site care timeframe is a reasonable midpoint for 

most GS projects and available data, including data submitted by commenters, do not support a 

different default timeframe, and has retained this in the final regulation. 

However, EPA recognizes that there may be sites 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 offers owners or operators flexibility regarding 

the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or 

lengthen the PISC timeframe during the post-injection period based on site-specific data, 

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

14
VI well owner or operator to demonstrate, during the permitting process based on substantial 

data, that an alternative PISC timeframe may be appropriate if it ensures non-endangerment of 

USDWs pursuant to requirements at §146.93(c). 

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

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

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

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

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

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

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

impacts. 

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

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

Comment: G. RCRA 

SEPCO agrees with the concept that Class VI wells should not be injecting 

hazardous wastes but is proposing some modifications to EPA’s definition of CO2 

stream in the rule. The modifications reflect the fact that the source of CO2 

should not be a factor in the context of defining the CO2 stream. The rule 

applies to the injection of CO2 and should not address the origins of the 

materials since that is beyond the scope of this regulation. The original text 

would have precluded injection of CO2 from some sources. 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 should not be arbitrarily prohibited; 

however, it is recognized that the presence of those impurities at sufficient 

concentrations may trigger the applicability of other statutory limits or 

requirements. Determining the type and levels of impurities in the CO2 stream is 

- absent a compelling public or environmental health risk - best left to 

contractual negotiations between partners in a CCS value chain as opposed to an 

arbitrary regulatory determination. The contracting parties are best able to 

evaluate the types of impurities, their compatibility with the reservoir and 

equipment, and determine the acceptable levels of those impurities in the stored 

CO2. To the extent that there is an overriding public interest in limiting the 

type or level of contaminants, principles of cost-effectiveness and riskmanagement should guide the decision making process. 

With specific respect to RCRA, SEPCo is concerned that EPA’s brief discussion of 

a supposed potential for injected CO2 streams to be characterized as hazardous 

waste (or some type of hazardous release) could have a significant chilling 

effect on the deployment of CO2 capture and sequestration technologies. Based on 

15
the work of our engineers and scientists with capture technologies and their 

extensive experience with the types of power plant flue gas likely to be sources 

of CO2 for sequestration, we do not believe that captured CO2 streams should 

trigger the application of RCRA. In addition, EPA’s Proposal suggests that 

injected CO2 may be considered hazardous waste for RCRA purposes, and defines 

"carbon dioxide stream" to exclude hazardous waste. 73 Fed. Reg. at 43503. The 

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

for such solid waste would turn on the specific composition of the CO2 in 

question. Id. Based on this premise, the preamble suggests, "EPA cannot make a 

categorical determination as to whether injected CO2 is hazardous waste under 

RCRA." Id. 

Rationale: 

The RCRA definition of "solid waste" does not include gaseous material unless it 

is "contained." RCRA 1004(27), 42 U.S.C. 6903(27). EPA has long taken the 

position that gasses do not qualify as "solid waste" under this definition 

unless they are "contained" in a cylinder or similar container. 54 Fed. Reg. 

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

are not solid waste, are not subject to the waste determination requirements of 

40 C.F.R. 262.11, and cannot be considered hazardous waste for RCRA purposes. 

The RCRA definition of solid waste is limited to "solid, liquid, semi-solid, or 

contained gaseous material." RCRA 1004(27). Because supercritical CO2 is none of 

these things; a plain reading of the statutory text suggests that supercritical 

CO2 should not be considered "solid waste." This reading of the statute makes 

sense, because RCRA is plainly aimed at the kind of material that could end up 

being dumped into a landfill. Uncontained supercritical CO2 is not such a 

material. Instead, the physical properties of supercritical CO2 are such that it 

would immediately vaporize -- becoming an uncontained gas -- before it could 

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

the fact that the hazardous characteristics -- the broad waste determination 

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

hazardous waste -- are based largely on test methods that are inapplicable to 

materials such as supercritical CO2. In particular, the toxicity characteristic 

depends on test methods that can only be applied to materials that are solids or 

liquids at standard temperatures and pressures. This is unsurprising, because 

the toxicity characteristic was designed to assess the threat waste would have 

in a municipal landfill disposal scenario, a scenario that -- as already 

discussed -- is inherently inapplicable to supercritical CO2. Accordingly, it 

makes no legal, policy, or practical sense to treat uncontained supercritical 

CO2 as "solid waste" for RCRA purposes. EPA should therefore confirm that 

uncontained supercritical CO2 is not "solid waste" and is not subject to RCRA 

waste determination requirements. 

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

16
actually in the form of a liquid (i.e., a liquid containing dissolved CO2). In 

such a case, the liquid would meet the statutory definition of "solid waste," 

the requirement to perform a RCRA waste determination would be triggered, and 

the familiar test methods for waste determinations could be applied. 

Recommendations: 

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

respect to the RCRA status of CO2. 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 concerns that geologic sequestration could be 

encumbered with those requirements except possibly through the commingling of a 

captured CO2 stream with an actual waste stream. 

Individual Response: With respect to RCRA, EPA has decided to initiate a separate proposed 

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

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

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

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

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

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

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

notes that the final GS rule, which adds new regulations for Class VI wells under the Safe 

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

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

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

USDWs from endangerment. 

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

Comment Code: 3140 2.1.4 Comments that the proposed geologic 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 with 

sufficient permeability, porosity, thickness and lateral extent and a low17
permeability confining zone with sufficient 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 for codification at 40 C.F.R. 146.83(a). Unfortunately, 

the preamble goes on to suggest the need for 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 Administrator 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 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 ensure 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 an elaborate 

evaluation of site conditions to address concerns related to seismicity and 

potential geochemical interactions. In fact, however, seismicity and geochemical 

compatibility are issues that are easily addressed in the GS context, and 

requirements for unnecessarily elaborate analysis would serve only to burden and 

impede the development of GS projects. 

Concerns with respect to seismicity are frequently raised in the injection well 

context, but there is ample experience demonstrating that such risks are modest 

and easily addressed through appropriate injection pressure limitations. 

Similarly, geologic compatibility -- while it can present issues in some 

contexts -- is unlikely to present any serious problems in the GS context. These 

conclusions are confirmed by decades of experience with 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 extremely corrosive hazardous wastes 

demonstrates -- cannot reasonably be expected to cause any breach of containment 

that would endanger a USDW. The proposed rule expresses specific concern about 

geochemical reactions that could alter the composition of the injected CO2 

stream -- particularly through the mobilization of contaminants that occur 

naturally in the injection zone -- but such concerns are immaterial because the 

specific composition of the CO2 stream matters little as long as the CO2 remains 

confined. Another theoretical concern relates to the potential for geochemical 

18
changes to contribute to the plugging of pore spaces in the injection 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 subsequent 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 permeability 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. Accordingly, 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 monitoring wells are needed to evaluate the 

impact" of potential geochemical changes 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 siting of a GS well and are the foundation for a detailed 

understanding of the local and regional geology. Collecting and evaluating geochemical data in 

and around the CO2 injection zone, as required in §146.82(a)(6), serves several purposes. This 

baseline geochemical data can help predict geochemical reactions between the injectate, 

reservoir geology, and formation fluids. Such reactions can lead to dissolution and precipitation 

of minerals which affect formation porosity, which in turn can affect required injection pressure 

(Sminchak and Gupta, 2002) and transport of fluid within the formation. While the confining 

layer is the primary barrier to CO2 movement into a USDW, multiple barriers are important and 

changes in injection pressure and fluid movement may compromise those barriers. An increase in 

injection pressure due to reduced porosity, in particular, can lead to fracturing of the confining 

layer and potentially allow fluid movement outside of the injection zone. Losses in injectivity 

because of geochemical reactions may also require additional injection wells and further 

penetrations in the confining layer that can become pathways for fluid migration. 

EPA disagrees with the comment that the composition of the CO2 stream is not important. 

Information about the composition of the CO2 stream informs decisions about the appropriate 

design and construction of the well, the potential for adverse mineral reactions in the subsurface 

geologic formations, and appropriate testing and monitoring parameters. 

EPA disagrees that injectivity is not an important consideration. While increasing storage 

capacity is not the intent of the UIC requirements, EPA believes that maximizing the amount of 

CO2 that can be injected through a single well may reduce the need for additional injection wells 

which reduce the potential for unacceptable fluid movement and improve USDW protection 

from endangerment. 

19
Finally, EPA disagrees that any of the requirements for detailed analysis of potential chemical or 

mineralogical reactions are unnecessary to ensure protection of USDWs 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 dissolution and precipitation of 

minerals which can affect formation porosity and injectivity, and in turn can affect required 

injection pressure (Sminchak and Gupta, 2002) and transport of fluid within the formation. 

Additionally, EPA disagrees that consideration of local and regional seismicity is not important. 

The site characterization provisions in the GS rule, including a review of the local and regional 

geology, and detailed review of any known or potential seismically active terrain in the vicinity 

of a proposed GS site are necessary to minimize the potential for induced seismic events or the 

reactivation of faults, which are a known potential risk associated with injection and are 

addressed in all aspects of the UIC regulations. 

Letter ID: 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 Final Rule should require, or allow the 

Administrator discretion to require, additional 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 protection of USDWs, a requirement 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 definition, 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 confining and 

containment zones above the injection zone would be unprecedented. No such 

requirement exists in the UIC program, even in the context of hazardous waste 

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

projects are currently underway (including Norway, Canada, Australia and 

Algeria). EPA should not single out GS for heightened and substantially more 

rigorous requirements than would be warranted on the merits of the actual risk. 

Recommendation: 

20
Require 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 adding a requirement of any secondary 

confining or containment zones. 

Individual Response: EPA believes that the Class VI requirements, including the level of site 

characterization required under §§146.82 and 146.83, appropriately address the unique 

challenges posed by large-scale GS including large injection volumes, the relative buoyancy of 

CO2, its corrosivity in the presence of water, the potential presence of impurities in captured 

CO2, and its mobility within subsurface geologic formations. 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 fluid movement, allow for pressure dissipation, and 

provide additional sites for monitoring, mitigation, 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 this 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 Corrective Action Requirements 

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

area of review ("AOR") for GS purposes. Modeling of the pressure effects 

associated with injection -- together with conservative modeling to bound the 

potential extent of CO2 plume movement -- are appropriate aids to the evaluation 

of geologic siting and corrective action to address risks presented by 

penetrations such as abandoned boreholes. The use of such modeling is already 

well established in the context of oil and gas exploration and production and 

has been used in the UIC program for "no-migration" petitions for hazardous 

waste injection. Similar modeling can reasonably be adopted for use in the GS 

context as well. 

Individual Response: EPA acknowledges the commenter’s support and agrees that predicting 

the complex multiphase, buoyant flow of the CO2, co-injectates, and compounds that may be 

mobilized due to injection requires the sophistication of computational models, as required at 

§146.84(c)(1). Models can predict CO2 fate and transport, as well as changes in formation 

pressure, in three dimensions, as a function of time in order to delineate the subsurface storage 

site and the AoR. Models can account for site-specific and predicted operating conditions as well 

as geologic heterogeneities and potential migration through faults, fractures, and artificial 

penetrations. 

21
Letter 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/Modeling 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 definition goes on to suggest that the AOR 

is to be "based on computation modeling 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 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 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 plume -- that matters, and modeling of 

chemical changes would be unnecessary. Similarly, the preamble suggests that the 

"most sophisticated" and most "accurate" modeling should be preferred 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 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., "may be impacted 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. 

Individual Response: EPA believes that predicting the complex multiphase, buoyant flow of the 

CO2, co-injectates, and compounds that may be mobilized due to injection requires the 

sophistication of computational models, as required at 146.84(c)(1). Models can predict CO2 fate 

and transport, as well as changes in formation pressure, in three dimensions, as a function of time 

in order to delineate the subsurface storage site and the AoR. Models can account for sitespecific and predicted operating conditions as well as geologic heterogeneities and potential 

migration through faults, fractures, and artificial penetrations. 

EPA acknowledges that fine precision may not always be necessary and that many factors 

determine ultimate confidence in modeling results. However, EPA does not believe that more 

22
precision would result in a less protective modeling approach. EPA anticipates that the owner or 

operator, in consultation with the Director, will choose the model that is most appropriate for a 

particular GS project, and that this dialogue is a key factor in assuring that the GS site is modeled 

(and eventually operated and tracked) in a manner that protects USDWs from endangerment. 

EPA encourages and expects owners or operators to use the best multiphase, computational 

models available. 

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 frequency (seeking comment) 

Comment: 2.Corrective Action 

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

scale of GS operations, EPA has proposed requirements for a corrective action 

plan contemplating 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 corrective 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 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 reevaluate the AOR should not be required. 

Individual Response: EPA believes that periodic AoR reevaluation at a set frequency is 

necessary to ensure protection of USDWs from endangerment and address the uncertainties 

inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure that a 

deliberate effort is made to verify, based on monitoring and operational data, that the CO2 plume 

is moving within the subsurface as predicted. EPA believes that less frequent reevaluations or 

planning reevaluations only when a need is demonstrated may not be sufficient to appropriately 

model plume and pressure front movement, establish conditions for corrective action, and ensure 

protection of USDWs from endangerment. EPA agrees that site-specific factors should be 

considered in the reevaluation schedule, and notes that the AoR and corrective action plan must 

specify the site-specific monitoring and operational conditions that warrant reevaluation, as 

specified in §146.84(b)(2)(ii). 

EPA clarifies that if site monitoring data agrees with the existing AoR delineation, a model 

recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration 

23
that the current AoR delineation is adequate 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 are sufficient to ensure that injected 

fluids cannot escape from the intended injection zone via the injection well 

borehole. The proposed rule would nevertheless impose substantially more costly 

well construction requirements resembling those for Class I hazardous waste 

injection wells. The proposed rule specifically cites the buoyancy of CO2 as the 

justification for these requirements. See 73 Fed. Reg. at 43509. 

SEPCo argues that the buoyancy of CO2 in no way justifies the additional 

construction requirements proposed. The reason for this is straightforward: by 

far the greatest driving force for fluid migration along an injection well 

borehole is the pressure build-up (or "cone of influence") caused by fluid 

injection during the operation of the injection well. The magnitude of this 

pressure influence is at its maximum at the point of injection, and -- within 

the injection interval -- it generally falls off logarithmically with lateral 

distance from the injection well borehole. At some distance from the injection 

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

decline to the point where density-driven flow (i.e., buoyancy) could become 

significant (at least in relative terms) as a driver for vertical fluid 

migration. At the injection well, however, the induced pressure gradient caused 

by the injection activity would so dwarf the impact of buoyancy as to render the 

latter insignificant. 

In short, buoyancy can be significant as a driver for lateral fluid movement, 

but provides a relatively weak driver for vertical fluid flow that -- at the 

point of injection -- 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 injection wells. 

Individual Response: As described above, EPA believes that GS is sufficiently different from 

Class II ER operations to warrant the tailored construction requirements for Class VI wells at 

§146.86. 

24
EPA disagrees that buoyancy is not a consideration that needs to be addressed in the GS 

regulations. Field and laboratory studies that evaluated two deep wells exposed to CO2 for 

nearly three decades have provided evidence of upward vertical flow of CO2. In Carey, et al. 

(2007), a sample of well cement collected from a section of well in the confining zone at 

SACROC showed evidence of cement alteration (carbonation) due to exposure from CO2. (The 

study was not able to determine whether the alteration was due to exposure to CO2 in the 

presence of water, dry CO2, or to a CO2-brine mixture.) In Crow, et al. (2009), a similar study 

was conducted on a CO2 production well that was drilled into and completed in a natural CO2 

producing formation. This study concluded that CO2 had caused alteration (carbonation) of the 

well cement and acidification of fluids adjacent to the caprock. The study could not determine if 

the alteration was due to exposure from CO2 diffusion up into the 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 overlying caprock. These observations, especially in 

conjunction with the larger CO2 volumes and higher reservoir pressures anticipated with GS, 

justify the well construction requirements in the final GS rule in order to prevent deterioration of 

the materials between the well casing and the well bore that can result in unacceptable fluid 

movement. 

EPA adds that buoyancy of CO2 is one of several considerations for large scale GS that warrant 

the tailored construction requirements at §146.86. For example, seismic surveys at Sleipner 

showed that CO2 had migrated to the top of the 200 to 300 meter thick formation as early as 3 

years after injection began. The overall behavior of CO2 at Sleipner is for it to migrate to the top 

of the formation and spread laterally from there (Chadwick, et al. 2006). Additionally, CO2 has 

the potential to be corrosive (in the presence of water or aqueous formation fluids during CO2 

injection), and the volume of CO2 anticipated to be injected in Class VI wells is significantly 

greater than for Class II ER/ CO2 injection wells. 

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 requirements for a surface casing cemented to 

the surface, for injection through a tubing and packer, and for a well design 

that permits continuous monitoring of a pressurized annulus. The requirement 

SEPCo finds objectionable is that for continuous cement 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 this performance standard are heavily 

dependent on site-specific conditions and are most appropriately determined in 

the permitting process. 

Recommendation: 

25
Utilize Class II well construction standards for the Class VI program. The 

proposed design standard mandating continuous cement for the long string casing 

should be deleted as unnecessary and unduly burdensome. 

Individual Response: EPA believes that the requirements for long-string casing are appropriate 

and offer appropriate flexibility: §146.86(b)(3) requires that the long-string casing extend to the 

injection zone and be cemented by circulating cement to the surface in one or more stages. It 

does not, however, specify how cementing would be accomplished, and gives flexibility to the 

owner or operator to propose alternate methods to provide a sufficient amount of cement to meet 

the standard that USDWs are protected from endangerment, subject to the approval of the 

Director. 

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 construction requirements in the preamble to the 

final GS rule for additional information. Additionally, EPA is developing guidance on the 

construction of Class VI wells. This guidance will be available on EPA’s website at 

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

EPA adds that other aspects of the rule allow flexibility based on site-specific 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 construction based on site-specific information 

about the injection project, including injection pressures, injection and confining zone lithology, 

and information about the carbon dioxide stream, as provided in 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 corrosion-resistant casing. 73 Fed. Reg. at 43510. These 

requirements are based on the premise that CO2 is corrosive and that experience 

with CO2 injection in the EOR context suggests that corrosion is a significant 

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

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

the interaction of CO2 and water. This distinction is critical from a practical 

standpoint, because injected CO2 streams would often (if not generally) be 

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

CO2 would come into contact with naturally-occurring water in the subsurface, 

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

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

immediately displace water away from the point of injection, creating 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 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 -- 

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

wells must be designed and constructed to resist a particularly 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). However -- 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-resistant construction or the occurrence of 

corrosion-related problems. 

Well construction requirements under the UIC program generally require that 

operational conditions and the nature of formation fluids and proposed injectate 

be considered in well construction, and these general requirements have served 

well. Thus, while there may be some Class VI CO2 injection scenarios in which 

corrosion-resistant materials may be required, there is no technical basis for 

any general presumption that they are necessary or should be required. 

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 -- and 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 recovery, and that this practice has led to the 

development of many corrosion mitigation measures that would be appropriate for the design of 

Class VI wells. The rule does not specify materials to be used; rather, it provides owners or 

operators with the flexibility to choose, as long as the materials used in Class VI wells are 

compatible with fluids with which they may come into contact and meet or exceed standards 

developed for such materials by API or ASTM International, or comparable standards approved 

by the Director, as provided at §146.86(b)(1). 

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

27
corrosive to well materials. Reference to corrosiveness of the CO2 stream in §146.86 is intended 

to mean CO2 in the presence of water or formation fluids. EPA also notes that while a "dry out 

zone" (i.e., an area that is free of liquids) might form during injection (e.g., Birkholzer, et al. 

2008), no modeling study or other information is available about the 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 including field, laboratory, and 

modeling studies have found that pH drops in the formation fluid, indicating at least partial 

mixing of the carbon dioxide and formation water (Kaszuba, et al. 2005; Kharaka, et al. 2006; 

Birkholzer, et al. 2008). The risk of creating acidic fluids that could come in contact with well 

materials and cements is addressed by the construction requirements in §146.86 to ensure 

protection of USDWs from endangerment. 

EPA disagrees that the casing, cement or other materials should only be designed for the period 

of the injection process, rather than the life of the sequestration project. GS projects are 

anticipated to have long life spans in comparison to other types of deep injection wells. Not only 

must Class VI wells be able to function safely and properly over the lifespan of the GS project, 

but they must be constructed such that USDWs remain protected after well plugging. The 

requirements at §146.86 will ensure that the well can maintain integrity throughout the proposed 

life span of the project, including after the injection well is plugged and through the postinjection site care period and beyond. While the risk profile of a GS site will decrease following 

cessation of injection, EPA believes that Class VI wells must be designed to protect USDWs 

from endangerment for the life of the project. Furthermore, rigorous casing and cementing help 

ensure that the Class VI well will not serve as a conduit for movement of fluids associated with 

future injection operations. 

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 pressure during injection does not initiate 

new fractures or propagate existing fractures in the confining zone adjacent to 

the USDWs. In no case shall injection pressure cause the movement of injection 

28
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 regulatory 

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 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 restrictive requirements designed not just 

to prevent endangerment of USDWs, but to ensure that there is no fracturing 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 

sequestration, 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 wells should be based on 

the existing Class II requirements, modified slightly to address the possibility 

of Class VI injection occurring above the 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 pressure during injection does not initiate 

new fractures or propagate existing fractures in the confining zone. In no case 

shall injection pressure cause movement of injection or formation fluids that 

endangers an underground source of drinking water. 

Individual Response: EPA believes that the injection pressure limits in the GS rule are 

important to protect against fracturing of the confining zone, and that the requirement at 

§146.88(a) that the pressure in the injection zone not exceed 90 percent of the fracture pressure 

provides a margin of safety in the well operation and protects USDWs from endangerment. 

The pressure limitations are tailored to the unique nature of CO2 injection for GS and afford 

flexibility to address site-specific 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 situ 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. 

29
The guidance will describe recommended approaches for characterizing the regional geology and 

hydrogeology of a proposed site and performing the necessary geochemical, geomechanical, and 

geophysical analyses of the injection and confining zone. EPA is also developing guidance for 

primacy agencies that will include recommended approaches for evaluating owner or operatorsubmitted data in setting permit conditions. The guidance will be available on EPA's web site, at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. The Department of Energy is 

developing a Best Practices Manual 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-off valves down hole 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 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 warranting costly additional safety measures that would 

interfere with monitoring and potentially with any necessary well remediation. 

Individual Response: After evaluating the risks and benefits of down-hole shut-off systems and 

considering additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from 

endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or operators of 

onshore Class VI wells install automatic surface shut-off devices. The rule affords Director's 

discretion to mandate automatic down-hole shut-off devices in onshore situations that may 

warrant their use. However, the Agency believes that offshore Class VI wells present unique 

construction and operational conditions, including isolation from shorelines and the need to 

construct wells through the water column and the subsurface, which may delay response time in 

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

offshore wells within State territorial waters install automatic down-hole shut-off systems. 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 currently used in situations where loss of well 

integrity could result in damage to the well or harm to humans (e.g., near high-density population 

areas, or in onshore acid gas injection; IEA, 2003). EPA has identified examples of documented 

logging techniques, including ultrasonic and temperature logs, that 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 automatic surface shut-off devices instead of down-hole devices for 

onshore wells provides more flexibility to owners or operators when performing required 

30
mechanical integrity tests. Additionally, this requirement addresses 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 sequestration 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 presence of water (including water with NOx, SOx, and 

H2S impurities) can be corrosive to well materials and cements. Thus, although a CO2 stream 

may be dry, the potential for corrosion of well materials down-hole, where the injectate can 

potentially mix with water in the target formation, must be considered. 

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

characterized the effects of carbonic acid on well materials. Laboratory studies (e.g., Kutchko, et 

al. 2007; Kutchko, et al. 2008; Akervoll, 2005) consistently identify alterations (typically 

carbonation) of cement as the result of interactions between cement and CO2-saturated brine. 

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

contact with CO2 in actual field (down-hole) conditions. Evaluation of cement from a well at the 

Scurry Area Canyon Reef Operators Committee (SACROC) site showed alteration, but did not 

show degradation that compromised the structural integrity of the cement (Carey, et al. 2007). In 

another study, cement samples were collected and analyzed from a CO2 production well in a 

natural CO2 reservoir in Colorado exposed to a CO2-water down-hole environment for 30 years 

(Crow, et al. 2008). The study found evidence of reaction between the CO2-rich water and the 

cement. 

Oil industry research also addresses the effects of corrosion of steel tubing and pipes. Lopez, et 

al. (2003) noted that 60 percent of oilfield failures are related to the effects of carbonic acid from 

produced brines on carbon and low alloy steels. A report by CO2 Norway (2004) notes that in 

some CO2 ER floods in the Permian Basin of Texas, bare carbon steel tubing has been used 

successfully. 

Laboratory investigation of cement alteration/degradation is an ongoing research area. Few fieldbased studies have been completed to date. Although the laboratory and field studies currently 

available suggest that corrosion problems may not be serious, there is not enough data to rule out 

potential corrosion problems of steel components of injection wells. Given the anticipated long 

lifespan of a Class VI well and the difficulties that would be associated with a corrosion-related 

31
well 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 injection 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 Testing (MIT) Requirements 

The proposed rule suggests, "MIT requirements for GS wells should be tailored to 

address the unique properties of CO2, specifically its buoyancy and potential 

corrosivity." 73 Fed. Reg. at 43513. As previously discussed, however, the 

buoyancy of CO2 is a relatively trivial factor in relation to the cone of 

influence created by injection pressure during injection, a factor that makes 

buoyancy virtually irrelevant as a driving force for upward migration through 

the injection well borehole during the operational life of a GS well. 

Accordingly, there is no basis to suggest that the buoyancy of CO2 is relevant 

to be considered in establishing mechanical integrity testing requirements for 

GS wells. Similarly -- as also previously discussed -- CO2 is not corrosive and 

cannot be expected to cause corrosion problems for the injection 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 not 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 for CO2 injection in 

the EOR/EGR context, and there is no reason why they should not be sufficient in 

the GS context as well. 

Individual Response: EPA disagrees with this comment. EPA has identified buoyancy as one of 

the unique characteristics of CO2 that warrants special consideration. The Agency believes that 

buoyancy of the injected CO2 coupled with other characteristics of GS operations, including the 

large injection volumes and timeframes of storage, present operating circumstances at Class VI 

wells that are different from other classes of wells and injectates regulated by the UIC Program. 

Supercritical CO2 has a lower density than the native formation fluids in the target injection 

formations typically anticipated for GS. Once injected, the more buoyant CO2 will have a 

tendency to migrate upwards. This expected movement is similar to the situation found in some 

Class I wells (see Revision to the Federal UIC Requirements for Class I--Municipal Wells in 

Florida; 65 FR 42234, July 7, 2000). Well monitoring in Florida identified upward fluid 

movement from some Class I municipal wells attributed to the lower density of the injection 

fluid (in this case due to lower TDS) compared to the native formation fluids. The injection 

fluids rose to the top of the injection zone preferentially through fractures. Such migration could 

32
occur through conduits in the injection wellbore as well as in the target formations. In the case of 

GS, any cracks or fractures in the cement casing for a GS injection well would also serve as 

conduits for upward migration of more buoyant fluids. External MITs, which test for movement 

along the borehole, are therefore appropriate requirements for GS wells. 

EPA disagrees that the MIT requirements for Class VI wells are excessive. MITs are a longstanding and proven method of providing early warning of potential problems in the injection 

well system before they lead to leakage and/or endangerment of USDWs. 

EPA also disagrees that corrosivity is not a concern. While some studies of cement performance 

have shown encouraging results, other information gathered through research and field data 

provided in the rulemaking docket, show evidence of chemical alteration and suggest a potential 

for degradation to occur and potentially endanger USDWs. Although laboratory and field studies 

suggest that corrosion problems may not be severe, such problems cannot be conclusively ruled 

out. Laboratory exploration of cement alteration and degradation is an ongoing research area, 

and field-based studies are very few. There also does not appear to be a clear consensus on the 

corrosion risks for the steel components of injection wells. Given the anticipated long lifespan of 

Class VI wells and the difficulties that would be associated with a corrosion-related well failure, 

EPA believes that the MIT requirements at §146.89 are justified. 

A comprehensive review of MIT results found that Class I wells injecting corrosive fluids fail 

MITs at rates two to three times higher than those that inject non-corrosive fluids (USEPA, 

1999). Given the potential for CO2 to be corrosive (when in the presence of water), there is a 

potential risk factor for MIT failure and the tailored MIT requirements are appropriate. 

EPA agrees that Class II well operators have decades of experience injecting CO2. However, 

EPA believes that significant operational differences exist between Class II and Class VI wells. 

For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly 

greater than for Class II wells. Also, reservoir pressure conditions will be different with ER 

production (extraction) serving to reduce reservoir pressure for Class II operations while Class 

VI injection operations will have no comparable de-pressuring activities. For these reasons, EPA 

believes that injection of CO2 for GS warrants more frequent MITs to provide sufficient early 

warning of the potential for MI failures due to the corrosivity of the CO2 or reservoir pressure 

conditions associated with CO2 GS. 

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 indicates, "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 

33
regulatory 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 injection demonstrates that plume and 

pressure 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 modeling demonstrations that can and 

should be relied upon to support determinations that injected CO2 will not 

endanger USDWs. 

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

the subsurface also does not consider the nature and utility 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 the 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 while there are similarities between injection of 

wastes for disposal (Class I) and GS (Class VI), there are significant differences as well. 

Important unique considerations for GS include the buoyancy of CO2, its corrosivity when in 

contact with water, its low viscosity (i.e., high mobility), and the very large injection volumes 

that are anticipated. There is also a degree of uncertainty regarding the behavior of large volumes 

of CO2 in the subsurface after injection. Given these characteristics of anticipated GS projects, 

EPA believes that plume and pressure front monitoring at §146.90(g) are justified to provide 

early warning of any unforeseen fluid movement that might endanger USDWs. 

EPA believes that pressure monitoring in the injection zone is necessary to track the 

development and movement of the pressure front and CO2 plume. Monitoring can also identify 

needed remedial actions, provide inputs for AoR reevaluation modeling, evaluate predictions of 

plume movement, and target additional geochemical and surface monitoring needs. Knowledge 

of the location of the CO2 plume and the associated pressure front will also assure the public that 

GS projects are proceeding according to plan, provide sufficient information to the owner or 

operator and Director, or allow for appropriate actions to address any indication that USDWs 

may be endangered. 

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), unless the Director determines based on site-specific geology, 

34
that such methods are not appropriate. For example, geophysical methods are difficult to execute 

in areas that are structurally and topographically complex or where lithologies have limited 

contrast in density, porosity, permeability, and other physical properties. EPA clarifies that this 

determination will be made by the Director based on the site-specific geologic information 

submitted by the owner or operator with 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 plan will include the site-specific details, 

technologies, testing and monitoring frequencies, 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 tests are an appropriate substitute for monitoring 

pressure changes in the injection zone. Pressure fall-off tests provide information only in the 

vicinity of the injection well(s) and measure pressure conditions within the injection zone only. 

Direct monitoring of pressure changes in the injection zone can provide advance warning of 

movement of CO2 or brine that might ultimately endanger a USDW. 

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 concerning such interactions should 

rarely if ever be relevant from a regulatory standpoint. In particular, USDWs 

are generally protected by ensuring that injected 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 that could actually compromise containment cannot reasonably be 

expected in the absence of truly unusual circumstances. Accordingly, any general 

requirement to monitor geochemical changes in the subsurface would be 

unreasonable. 

Individual Response: EPA disagrees with the commenter. While contamination is unlikely at 

properly selected, constructed, and operated sites, 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 monitoring wells sited based on site-specific information will provide 

direct information that is not otherwise obtainable and, along with other monitoring data, will 

support a broader understanding of fluid behavior at the site. 

35
EPA is developing guidance on testing and monitoring to assist owners or operators and 

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

guidance describes available technologies and recommended approaches for implementing a 

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

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

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

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

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

EPA adds that the iterative process of monitoring, modeling, and AoR reevaluation is 

appropriate to verify that the CO2 plume and pressure front are moving through the subsurface 

as predicted, verify the accuracy of the delineation model (or identify needed changes), and 

refine testing and monitoring activities to ensure that USDWs are protected from endangerment 

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 front tracking (seeking comment) 

Comment: 1. Monitoring CO2 Movement and Reservoir Pressure 

The preamble to the proposed rule specifically states that the "[m]onitoring of 

subsurface geochemistry and the position of the CO2 plume and pressure front are 

necessary to verify predictions of plume movement, provide inputs for modeling, 

identify needed corrective actions, and target geochemical and surface 

monitoring activities." 73 Fed. Reg. at 43514. Again, this is an assertion that 

cannot be reconciled with experience with Class I hazardous waste injection, 

where such monitoring has never been considered necessary and is not required. 

Individual Response: EPA disagrees that plume and pressure front monitoring are not justified 

for Class VI wells. The Agency recognizes that while there are similarities between injection of 

wastes for disposal (Class I) and GS (Class VI), there are significant differences as well. 

Important unique considerations for GS include the buoyancy of CO2, its corrosivity when in 

contact with water, its low viscosity (i.e., high mobility), and the very large injection volumes 

that are anticipated. There is also a degree of uncertainty regarding the behavior of large volumes 

of CO2 in the subsurface after injection. Given these characteristics of anticipated GS projects, 

EPA believes that plume and pressure front monitoring at §146.90(g) are justified to provide 

early warning of any unforeseen fluid movement that might endanger USDWs. 

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

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

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

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

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

appropriate. 

36
EPA believes that pressure monitoring in the injection zone is necessary to track the 

development and movement of the pressure front and CO2 plume. Monitoring can also identify 

needed remedial actions, provide inputs for AoR reevaluation modeling, evaluate predictions of 

plume movement, and target additional geochemical and surface monitoring needs. Knowledge 

of the location of the CO2 plume and the associated pressure front will also assure the public that 

GS projects are proceeding according to plan, provide sufficient information to the owner or 

operator and Director, or allow for appropriate actions to address any indication that USDWs 

may be endangered. 

Letter ID: 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 subsurface are problematic in a variety of 

respects. They are expensive to install, create potential pathways for vertical 

fluid migration, and -- in the deep subsurface where natural fluid movement may 

be very slow or effectively non-existent -- they have little potential to 

provide more than an isolated "point 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 the 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 benefit from monitoring wells designed to 

detect potential leakage from an injection zone, because the ability to detect 

such leakage is at best a hit-or-miss (if not a needle in a haystack) 

proposition. Monitor wells also have built-in confounding factors that include 

both the potential for well construction to impact fluid quality in the target 

sampling interval and the fact that sampling may itself cause fluid movement 

that might not otherwise occur. Because pressure fronts extend much further than 

injected fluid plume fronts during injection, pressure monitoring is more likely 

to be useful than fluid sampling, but costs would 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 Administrator to address particular 

circumstances at the site. See 52 Fed. Reg. 32446 at 32463-64 (August 27, 1987), 

53 Fed. Reg. 28118 at 28141, 28144-45 (July 26, 1988). Experience with hazardous 

waste injection does not commend the use of monitor wells even in that context, 

and there is no justification to impose as stringent an approach -- let alone a 

more stringent approach -- for the injection of CO2. 

Individual Response: As described above, EPA believes that monitoring using wells in the 

injection zone, e.g., for pressure monitoring as required at §146.90(g)(1), can be safely 

37
performed if the wells are constructed to prevent flow between the injection zone and USDWs or 

other layers above the confining zone. Such construction technologies exist and have been used 

in the oil and gas industry for years. EPA believes that properly constructed monitoring wells 

will be a safe way to obtain the data that is essential to ensure that the injected CO2 remains 

confined in the injection zone and that pressure changes are not causing movement of formation 

or other fluids. To mitigate the risk of fluid movement, EPA requires owners and operators to 

submit a testing and monitoring plan that describes how the owner or operator plans to site and 

construct monitoring wells. EPA is developing guidance on well construction that will include 

recommendations for monitoring well construction. The guidance will be available on EPA’s 

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

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

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

guidance describes available technologies and recommended approaches for implementing a 

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

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

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

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

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

EPA also acknowledges that complete coverage of the potential plume area or leakage in the 

subsurface is not possible through the use of monitoring wells. However, data from an 

appropriate number of monitoring wells sited based on site-specific information will provide 

direct information that is not otherwise obtainable and, along with other monitoring data, will 

support a broader understanding of fluid behavior at the site. 

EPA adds that the iterative process of monitoring, modeling, and AoR reevaluation is 

appropriate to verify that the CO2 plume and pressure front are moving through the subsurface 

as predicted, verify the accuracy of the delineation model (or identify needed changes), and 

refine testing and monitoring activities to ensure that USDWs are protected from endangerment 

and that there would be adequate warning of potential problems at the site before any 

endangerment could occur. 

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

believes that monitoring is essential for protection of USDWs at GS sites. Although a significant 

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

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

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 monitor wells, the proposed rule suggests that it may be 

38
possible to use remote geophysical techniques for "plume tracking." 73 Fed. Reg. 

at 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 general, the technologies available 

would be very expensive to employ on the scale required, and provide 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 unrealistic expectations for the technologies involved. In 

fact, the use of such techniques may do more 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 front. The owner or operator must 

use direct methods to monitor for pressure changes in the injection zone. Indirect methods (e.g., 

seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools) 

are also required unless the Director determines, based on site-specific geology, that such 

methods are not appropriate. 

EPA is affording Director's discretion regarding the use of geophysical techniques at some sites 

because the Agency recognizes that geophysical methods are not appropriate in all geologic 

settings. For example, geophysical methods are difficult to execute in areas that are structurally 

and topographically complex or where lithologies have limited contrast in density, porosity, 

permeability, and other physical properties. EPA clarifies that this determination must be made 

by the Director based on the site-specific geologic information submitted by the owner or 

operator with their permit application. 

There may also be interference from urban and residential 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 surveying. In fact, seismic and other geophysical and 

remote sensing methods have been used with success at GS pilot projects and are likely to be 

useful for plume tracking at many GS sites. StatOilHydro has used both time-lapse seismic and 

gravity methods to track the CO2 plume at the Sleipner 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 combination 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 monitoring to assist owners or operators and 

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

39
guidance describes available technologies and recommended approaches for implementing a 

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

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

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

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

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

EPA disagrees that monitoring at GS sites will undermine public confidence in GS and the UIC 

Program. EPA believes that appropriately designed 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 appropriate measures are taken to protect 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 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: 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 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 confounding factors. Worst of all, such monitoring would be aimed at leakage 

of CO2 all the way to the surface, which -- in the case of any properlypermitted GS project -- would by definition 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 potential for possible leakage pathways 

should be demonstrated and managed during the permitting process. 

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

subsurface formations are the first line of monitoring that would allow detection of potential 

endangerment to USDWs from GS activities (this is required at all GS sites, as described at 

40
§146.90(d)). 

The Agency also believes that surface air and soil gas monitoring, when coupled with subsurface 

monitoring, may be appropriate at some GS projects to ensure USDW protection. EPA 

acknowledges that surface air and soil gas monitoring may not be suitable in all settings as a 

method to ensure USDW protection. However, EPA does not believe that this should entirely 

preclude their use. The decision to use surface monitoring and the selection of monitoring 

methods will be site-specific (e.g., may be influenced by geology, injection depth, and 

operational conditions) and must be based on potential risks to USDWs within the AoR. 

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

discretion of the Director as a means of identifying leaks that may pose a risk to USDWs and 

informing emergency notification of a Class VI owner or operator and UIC Director in the event 

of a USDW endangerment, pursuant to requirements at §146.91(c). 

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 post-operational period of observation and 

"site care" prior to closure. The requirements contemplated -- including a 

presumptive 50-year post-injection 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 years -- are subject to such burdensome 

post-injection requirements. 

Long term protection of USDWs is ensured up-front, primarily through proper 

siting as confirmed through the technical evaluation that occurs in the 

permitting process. Proper well construction, operating, monitoring and testing 

provide assurance against problems during the operational life of an injection 

well, but siting doesn’t change, and proper siting must be ensured at the start. 

Once injection operations cease, there should generally be no need 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 certainly should be sufficient for the injection of CO2. The 

premise that careful siting and AOR evaluation are not enough -- that actual 

monitoring for decades after the cessation of injection is needed -- is foreign 

to the UIC program and inconsistent with 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 

41
commercial 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 shorten the post-injection site care period 

would depend on the apparently unlimited discretion of the Director and could 

not be assessed in any meaningful way 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-injection site care period. The burdens and regulatory 

uncertainties of an extended post-injection site care requirement cannot be 

justified, especially in the context of a regulatory program that requires a 

"non-endangerment" demonstration 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 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 circumstances where it can be demonstrated 

in less than 50 years that the plume and pressure front no longer pose a risk of endangerment to 

USDWs. For this reason, the GS rule offers owners or operators flexibility regarding the duration 

of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC 

timeframe during the post-injection period based on site-specific data, pursuant to requirements 

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

to demonstrate, during the permitting process based on substantial data, that an alternative PISC 

timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to 

requirements at §146.93(c). 

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

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

timeframe represents a reasonable and protective monitoring period 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 review of research studies, industry reports, and 

existing environmental programs, and evaluation of public comments. 

EPA agrees that proper site characterization, well construction, and operation are important 

components of ensuring that USDWs are protected. However, EPA disagrees that this is a 

substitute for post-injection site care. EPA believes that extensive post-injection monitoring is 

necessary to protect USDWs from endangerment. 

EPA disagrees that the rule affords ¿unlimited discretion¿ to the Director to lengthen the postinjection site care timeframe. Because of the variety of site-specific circumstances at GS sites, 

EPA believes that Directors, in consultation with operators, will be in the best position to 

42
determine whether additional post-injection site care monitoring is needed (or whether the 

timeframe may be shortened), based on the circumstances of a particular project. EPA expects 

this decision to be made based on relevant site data, 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 years based on a review 

of research studies, industry reports, and existing environmental programs. This analysis was 

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

Computational Modeling of Underground Injection of Carbon Dioxide for Determination of 

Area-of-Review and Potential Risk to Underground Sources of Drinking Water. EPA assessed 

various default timeframes based on additional review of research studies and evaluation of 

public comments. While numerous commenters suggested that EPA shorten the monitoring 

timeframe, none of the commenters provided sufficient data or other evidence to warrant a 

change in the proposed timeframe. While the 10- or 30-year timeframe suggested by some of 

these commenters may be within the timeframe suggested in some studies, EPA believes that the 

potential risks of endangering USDWs will likely not decline within these timeframes and 

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

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

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

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

meet the requirements provided at §146.93(c). 

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

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

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

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

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

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

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

impacts. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells; demonstrate 

the appropriateness of an alternative post-injection site care time frame; perform post-injection 

monitoring; demonstrate non endangerment; and perform site closure activities. This guidance 

will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

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

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

CFR 146.85) 

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Comment: H. Financial Assurance 

SEPCo supports EPA’s flexible approach on financial assurance methods. It would 

be a mistake to impose any regulatory restrictions that would preclude the use 

of particular types of financial assurance or particular instruments, regardless 

of whether those are currently used for other classes of injection wells or in 

other EPA programs. Allowing for flexibility recognizes that operators are 

likely to use combinations of approaches and instruments to meet these 

requirements and that these combinations may change significantly over time as 

operators, program Directors and the financial markets gain more experience with 

geologic sequestration projects. EPA is wise to avoid any artificial constraints 

on the development of potentially acceptable means of achieving financial 

assurance. 

Recommendation: 

Recommend that this approach be retained in the final rule. 

Individual Response: As described above, owners or operators 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 responsibility must be demonstrated, including corrective 

action on wells in the AoR, injection well plugging, PISC and site closure, and emergency and 

remedial response.