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

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

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• 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.

### BEFORE THE UNI TED STATES

ENVIRONMENTAL PROTECTION AGENCY

____________________________________________ ) Notice of Proposed Rulemaking ) Federal Requirements Under the ) Underground Injection Control (UIC ) Program ) EPA-HQ-OW-2008-0390 for Carbon Dioxide (CO 2 ) ) FRL-8695-3 Geologic Sequestration (GS) Wells ) ) ) 73 Fed. Reg. 43492 (July 25, 2008) ) ____________________________________________)



### Individual Additional Comments

of the

Natural Resources Defense Council

A. Introduction

The Natural Resources Defense Council (NRD C) thanks EPA for the opportunity to comment on the Proposed Rule on carbon dioxide sequestration wells under the Underground Injection Control (UIC) Program.

NRDC is a national, nonprofit organization of scientists, lawyers and environmental specialists dedicated to protecting public health and the environment. Founded in 1970,

NRDC has more than 1.2 million members and online activists nationwide, served from offices in New York, Washington D.C., Sa n Francisco, Los Angeles, Chicago and Beijing.

NRDC has submitted the bulk of its comments on the proposed rule jointly with the

Clean Air Task Force, Clean Water Acti on, Environmental Defense Fund and Western

Resource Advocates. We submit these additional comments to cover three areas on which we would like to draw particular attention and elaborate on our views. These areas are:

• the definition of GS and authority, an d sequestration in hydrocarbon reservoirs;

• pressure management; and

• closure.Having participated in the discussions of the multi-stakeholder group that will be submitting comments on the same topics, we felt that good progress was made towards forming a consensus on these topics. Nonetheles s, we felt unable to sign on to those joint recommendations and proposed language, for r easons that will become clear below. We appreciated the extension of the public co mment period that was granted by Assistant Administrator Benjamin Grumbles, announced in the Federal Register on November 21 and confirmed in Director Cynthia C. Dougherty’s letter of November 24.



### B. Definition of GS

Geologic sequestration and authority

In the proposed rule, EPA has defined geologi c sequestration as fo llows [FR p. 43535, §146.81(d)]:

“Geologic sequestration means the l ong-term containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. This term does not ap ply to its capture or transport.”

The proposed rule has cited authority for EPA to regulate GS under the Safe Drinking

Water Act. However, we believe that EPA sh ould exercise its authority under the Clean Air Act as well to regulate GS for the added purpose of preventing releases to the atmosphere, and not just for the purpose of protecting USDWs. Under such authority, the Agency should ensure that any wells permitted for the purposes of GS meet an adequate permanence standard, such as that already pr omulgated in the UIC rules by the state of Washington, which was based on the IPCC’s findings in its Speci al Report on Carbon Capture and Storage 1 :

“ Permanent sequestration means the retention of greenhouse gases in a containment system using a method that is in accordance with standards approved by the department and that creates a high degree of confidence that substantially ninety nine percen t of the greenhouse gases will remain contained for at least one thousand years.” 2

Under this added authority, EPA should ensure th at Class VI is adequa te for the purposes of protecting USDWs and for preventing releases of CO 2 to the atmosphere.

1 In its technical summary, IPCC’s Special Report on Carbon Capture and Storage states that “With regard to global risks, based on observations and analysis of current CO 2 storage sites, natural systems, engineering systems and models, the fraction retained in appropriately selected an d managed reservoirs is very likely to exceed 99% over 100 years, and is likel y to exceed 99% over 1000 years. Similar fractions retained are likely for even longer periods of time, as the risk of leakage is expected to decrease over time as other mechanisms provide additional trapping.”

2 WAC 173-407-110 Definitions to Part II.Other wells permitted for GS, whether for that sole purpose or for GS and other purposes, should also be subject to regulatory require ments sufficient both to protect USDWs and to prevent releases of CO 2 to the atmosphere. Such requirements include, but are not limited to, adequate site characterization, monitoring, modeling, corrective and remedial

action and closure standards, as well as other requirement s that EPA has proposed for

Class VI. We cannot endorse the classification of either Class II (a s was proposed or as modified by some other commenters) wells or Class VI wells as proposed by EPA in the rule, as the definition only covers protection of USDWs.

Sequestration in hydrocarbon reservoirs

We also wish to comment on the distin ction between a Cla ss II EOR project and sequestration in oilfields. Currently, EOR operators purchase CO 2 for injection at an expense. Consequently, CO 2 is a valuable commodity to EOR operators and is treated accordingly. CO 2 purchases from natural, and, to a lesser extent, anthropogenic sources, represent a major cost to a CO 2 -EOR operation, often as high as 50% of overall project costs. As such, operators have had a st rong incentive to minimize the amount of CO 2 purchased and injected, and frequently have relied on the injection of water alongside the

CO 2 in a process known as Water-Alternating- Gas (WAG). To minimize the amount of

CO 2 purchased, CO 2 is not intentionally emitted or vented to the atmosphere during operations or after operati ons cease. Any injected CO 2 that returns to the surface during production operations is separated from the hydrocarbons and re-inj ected for additional enhanced recovery use. Approximately 30% to 50% of the injected CO 2 volume typically remains in the oil or gas reserv oir after production operations cease.

However, this current economic rationale for recycling CO 2 does not assure long-term retention of the injected CO 2 for several reasons and thus does not provide a basis for assuming that either “business as usual” EO R activities or EOR activities modified to

increase amounts of CO 2 injected should qualify as GS, without additional showings and regulatory requirements. Accordingly, no we lls permitted only under Class II rules as they now stand should be treated as GS activities.

Long-term retention of injected CO 2 in Class II wells is not assured, first, because current recycling activities are based on economic incentives that can change as the market price for purchasing CO 2 changes. Second, the economic incen tive to prevent leaks ends when

CO 2 purchases for additional production ceases . Third, the fields where EOR is being practiced were not selected specifically for their suitabili ty for long-term CO 2 retention and were not subject to any re gulatory screening to assess su ch suitability. Fourth, in a

carbon constrained-world, where there is an economic incentive to maximize the amount

of CO 2 injected in oilfields, additional injection could lead to a change in the risk profile to USDWs that exceeds common practice of Cl ass II operations to date. Current Class II operations have no real reason or incentive to exceed the original rese rvoir pressure in the oilfield: the resulting pressure drop after prim ary recovery is only partly compensated for or equaled during secondary and tertiary reco very. Exceeding original reservoir pressure

could lead to conditions that are closer to or exceed the tensile or shear fracture limits ofthe reservoir or fault slippage pressures. The additional pressure could also affect a given caprock’s ability to prevent CO 2 or other reservoir fluid leak age through it, as pressure approaches or exceeds the capillary entry pr essure for the caprock. Finally, the larger

volumes of CO 2 injected could lead to CO 2 or reservoir fluids approaching of breaching spill points in the reservoir, and/or a greater volume of displaced flui ds and a larger area of elevated pressure.

Similar considerations prevent wells regulat ed under other existing UIC classifications from being treated as GS activities.

For all of these reasons, we oppos e any approach that allows we lls that are not subject to the necessary requirements to be defined and treated as GS activities. All CO 2 injection

activities that are tr eated under EPA rules as GS proj ects to protect USDWs and to prevent releases to the atmo sphere, whether conducted sole ly for GS purposes or for additional purposes, must be reviewed and pe rmitted pursuant to adequate rules set forth for those injection activiti es. EPA should promulgate such rules under the current rulemaking for Class VI, taking into account di fferences in target reservoir types as

needed.



### C. Pressure management

[FR p. 43538, §146.88(a)] EPA has propos ed to adopt an injection pressure limit equal to 90 percent of the fracture pressure in the inje ction zone. This is a high number, and there will be cases where it is prudent to lower limits . Since injection is likely to take place in diverse geologic settings, we believe that t hose limits should be ca lculated individually, taking into account a number of geologic factors each time, which we attempt to incorporate in the proposed language below. Nonetheless, we believe that EPA should maintain a maximum upper limit (equal to or less than 90 percent of the fracture pressure in the injection zone), so as to avoid cases where studies might a ppear to support higher

limits that would not be advisable. We also consider the “Except during stimulation” qualifier as confusing a nd creating a loophole and we urge that it be removed. Finally, the pressure limits themselves should refer to th e confining zone and not the injection zone. We offer the following langua ge as a starting point:

“The owner or operator must ensure that injection pressure does not exceed [90] percent of th e fracture pressure of the confining zone. The owner or operator must comply with a maximum injection pressure limit approved by the Director and specif ied in the permit. In approving a maximum injection pressure limit, the Director must consider the results of well tests and, where appropriate ge omechanical or other studies, that

assess the risks of tens ile failure and shear failure. Limits shall be calculated so as to assure that pressure will avoid initiation or propagation of fractures in the confining zone or cause otherwise non-transmissive faults transecting the confining zone to become transmissive. In no casemay injection pressure cause movement of injection or formation fluids that endangers a USDW.”

The maximum upper limit should not be used as a default in place of tests and studies that should be used to establish appropriate limits for specific sites – we urge EPA to ensure that this is built into the rule langua ge. The consideration of both tensile and shear failure is necessary in carrying out a rigo rous evaluation, in our view, as is the requirement not to cause otherwise non-transmi ssive faults transecting the confining zone to become transmissive. We also urge EPA to compile a list of quality criteria against

which the results of the mentioned tests and st udies will be evaluated – these need to be transparent and capable of screening adequate tests from inadequate ones. Pressure limits

should also ensure that no si gnificant risks from seismicity are posed, and EPA should incorporate appropriate language in the setting of pressure limits.

We further believe that the esta blished phrasing “so as to assure that”, used in Class II, is preferable to other formulations such as “with a reasonable degree of certainty”. We also believe that the proposed rule’s language on movement of fluids “that endangers a USDW” is more protective and preferable to the wording “into a USDW”, and preferable to references to §144.12(a). As mentioned above , the rule should be drafted to assure no releases to the atmosphere as well.



### D. Closure

[FR p. 43540, §146.93(b)] EPA has proposed an arrangement whereby the operator continues to monitor the site for a minimum of 50 years after the cessation of injection, unless the operator can demonstrate to the satis faction of the Director that the project no longer poses an endangerment to USDWs and that the CO 2 plume and pressure front have

stabilized.

While 50 years is not a number that will apply in all cases and projects, we do believe that it is appropriate as a default at toda y’s level of our unders tanding and operational experience with GS. The option that operators have under the current proposal to obtain approval for a lower number, based on actual proj ect performance, should be sufficient to deal with situations where 50 years can be demonstrated to be unnecessarily long. Along the same lines, there might be situations wh ere 50 years would not suffice, and where the Director should require a l onger period, as per the curren t proposal. In assessing nonendangerment to USDWs and plume/pressure fr ont stabilization, we be lieve that the EPA should be far more specific in its requireme nts. We offer the following language as a suggested revision to §146.93(b):

“(b) The owner or operator shall m onitor the site following the cessation of injection.

(1) The owner or operator shall co ntinue to conduct monitoring as specified in the Director-approved post-i njection site care and site closureplan for at least 50 years following the cessation of injection or until

closure is authorized.

(2) If the owner or operator can demonstrate to the satisfaction of the Director before 50 years, based on/pur suant to the criteria in (b), that the geologic sequestration project does not and is not expected to pose an endangerment to USDWs or result in releases to the atmosphere, the Director may approve an amendment to the post-injection site care and site closure plan to reduce the freq uency of monitoring or may authorize

site closure before the e nd of the 50-year period.

(3) Prior to authorization for s ite closure, the owner or operator

must demonstrate to the Director, ba sed on monitoring, other site-specific data, and modeling that is consistent with site performance, that no additional monitoring is needed to a ssure that the geologic sequestration project does not and is not expected to pose an endangerment to USDWs or any release to the atmo sphere. The owner or operator must demonstrate, based on the current understanding of the site, including monitoring data and modeling, all of the following: (i ) the magnitude and extent of the project footprint (CO 2 plume and the area of elevated pressure); (ii) the

location of the detectable CO 2 plume; (iii) that there is no significant leakage of either CO 2 or displaced formation fl uids that is endangering USDWs or creating a potential release to the atmosphere; (iv) that the injected or displaced fluids are not e xpected to migrate in the future in a manner that encounters a potential leakage pathway into a USDW or to the atmosphere; (v) that the injection wells at the site completed into or through the injection zone or conf ining zone are plugged and abandoned in accordance with these requirements; and (vi) any remaining project monitoring wells at the site are being managed by a person and in a manner acceptable to the Director.

(4) If such a demonstration can not be made after the 50-year period, the owner or operator must s ubmit to the Director a plan to continue post-injection site care.”

In addition, given the desi red permanent nature of CO 2 sequestration in the subsurface and the importance to the public of ensuring long-term attention to oversight of project sites, EPA should adopt provisions to assure long-term stewardship of GS repositories. This framework should designate an entity with responsibility for monitoring and managing sites after closure has been authoriz ed. The proposed rule authorizes operators to stop monitoring, but does not provide for th e stewardship of sites following closure. This needs to be rectified by EPA. The agency should consider its authority not just under the Safe Drinking Water Act, but also under the Clean Air Act to provide the required stewardship framework. It is important that the post-closure framework include financing provisions that avoid hidden subsidies for priv ate sector operators and are adequate to ensure proper site stewar dship in the long-term.

### E. Conclusion

We appreciate the opportunity to provide comments to EPA on this most important rulemaking effort. We very much look forward to continuing to work with the Agency on this rule, as well as other efforts under the Agency’s existing authority to address the significant problem of climate change in the near term.

Respectfully submitted,

David Hawkins and George Peridas, Natural Resources Defense CouncilLetter ID: 0272

Commenter: David Hawkins Organization: Natural Re sources Defense Council

Letter ID: 0272 Comment ID: 24076 Letter Lines: 64 to 103 ; 300 to 309

Comment Code: 1210 1.1.1 Comments about the proposed rule

Comment Code: 1400 1.2 Comments on EPA's Authority to Regulate Injection of CO2

Comment: B. Definition of GS

Geologic sequestration and authority

In the proposed rule, EPA has defined ge ologic sequestration as follows [FR p. 43535, §146.81(d)]:

"Geologic sequestration means the l ong-term containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. This term does not appl y to its capture or transport."

The proposed rule has cited authority fo r EPA to regulate GS under the Safe Drinking Water Act. However, we believe that EPA should exerci se its authority

under the Clean Air Act as well to re gulate GS for the added purpose of preventing releases to the atmosphere , and not just for the purpose of protecting USDWs. Under such authority, the Agency shoul d ensure that any wells permitted for the purposes of GS meet an adequate permanence standard, such as that already promulgated in the UIC rule s by the state of Washington, which was based on the IPCC’s findings in its Sp ecial Report on Carbon Capture and Storage [FN1]:

"Permanent sequestration means the retention of greenhouse gases in a containment system using a method that is in accordance with standards approved by the department and that creates a high degree of confidence that substantially ninety nine percent of the greenhouse gase s will remain contained for at least one thousand years." [FN2]

Under this added authority, EPA should ensure that Class VI is adequate for the purposes of protecting USDWs and for pr eventing releases of CO2 to the atmosphere.

Other wells permitted for GS, whether for that sole purpose or for GS and other purposes, should also be subject to regul atory requirements sufficient both to protect USDWs and to prevent releases of CO2 to the atmosphere. Such requirements include, but ar e not limited to, adequate site characterization, monitoring, modeling, correctiv e and remedial action and closure standards, as

1well as other requirements that EPA has pr oposed for Class VI. We cannot endorse the classification of either Class II (as was proposed or as modified by some other commenters) wells or Cl ass VI wells as proposed by EPA in the rule, as the definition only covers protection of USDWs.

[FN1] In its technical summary, IPCC’s Special Report on Ca rbon Capture and Storage states that "With regard to gl obal risks, based on observations and analysis of current CO2 stor age sites, natural systems, engineering systems and models, the fraction retained in appropria tely selected and managed reservoirs is very likely to exceed 99% over 100 y ears, and is likely to exceed 99% over 1000 years. Similar fractions retained are likely for even longer periods of time, as the risk of leakage is expect ed to decrease over time as other mechanisms provide additional trapping."

[FN2] WAC 173-407-110 Defin itions to Part II.

Individual Response: EPA clarifies that the scope of the GS regulation is limited to injection of CO2, and that all requirements in the GS rule are designed for the purpose of protecting USDWs from endangerment. Consequently, this commen t is outside the scope of the rulemaking. The SDWA does not provide the UIC Program with the authority to develop re gulations for all areas related to GS, such as releases to the atmosphere.

EPA acknowledges that GS falls within the broade r context of CCS and the need for regulatory clarity to ensure that USDWs are protected from endangerment. In develo ping the final GS rule,

the Office of Water coordinated with other Agency program offices and across federal agencies (e.g., with the Department of Energy; United Stat es Geological Survey; Bureau of Ocean Energy Management, Regulation, and Enforcement, formerly the Minerals Management Service; Bureau of Land Management). The Agency continues to eval uate areas of potential applicability of other Federal environmental statutes including, but not limited to: the Clean Air Act; the Resource Conservation and Recovery Act; the Comprehe nsive Environmental Response, Compensation, and Liability Act; and the Marine Protection, Resear ch and Sanctuaries Act to various aspects of GS and CCS. The Agency will continue to coordinate on GS and CCS related issues to minimize redundancy and maximize efficiencies for owners or operators. For additional information, please see the discussion entitle d "How Does This Rulemaking Relate to Other Federal

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

Letter ID: 0272 Comment ID: 24077 Letter Lines: 105 to 163

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: Sequestration in hydrocarbon reservoirs

We also wish to comment on the distinc tion between a Class II EOR project and sequestration in oilfields. Currently, EO R operators purchase CO2 for injection at an expense. Consequently, CO2 is a valu able commodity to EOR operators and is

2treated accordingly. CO2 pur chases from natural, and, to a lesser extent, anthropogenic sources, represent a major cost to a CO2-EOR operation, often as high as 50% of overall project costs. As such, operators have had a strong incentive to minimize the amount of CO2 pur chased and injected, and frequently have relied on the injecti on of water alongside the CO 2 in a process known as Water-Alternating-Gas (WAG). To minimize th e amount of CO2 purchased, CO2 is not intentionally emitted or vented to the atmosphere during operations or after operations cease. Any injected CO2 that returns to the surface during production operations is separated from the hydrocarbons and re-injected for additional enhanced recovery use. Approximately 30% to 50% of the injected CO2 volume typically remains in the oil or gas rese rvoir after production operations cease.

However, this current economic rationale for recycling CO2 does not assure longterm retention of the injected CO2 for se veral reasons and thus does not provide a basis for assuming that either "business as usual" EOR activities or EOR

activities modified to increase amounts of CO2 injected should qualify as GS, without additional showings and regulatory requirements . Accordingly, no wells permitted only under Class II rules as they now stand should be treated as GS

activities.

Long-term retention of injected CO2 in Class II wells is not assured, first, because current recycling activities are based on economic incentives that can change as the market price for purchas ing CO2 changes. Second, the economic incentive to prevent leaks ends when CO2 purchases for additional production ceases. Third, the fields where EOR is being practiced were not selected specifically for their suitability for lo ng-term CO2 retention and were not subject to any regulatory screening to assess such suitability. Fourth, in a carbon constrained-world, where there is an economic incentive to maximize the amount of CO2 injected in o ilfields, additional injection could lead to a change in the risk profile to USDWs that exceed s common practice of Class II operations to date. Current Class II operations have no real reason or incentive to exceed the original reservoir pressure in the oilfield: the resulting pressure drop after primary recovery is only partly compensated for or equaled during secondary and tertiary recovery. Exceedi ng original reservoir pressure could

lead to conditions that are closer to or exceed the tensile or shear fracture limits of the reservoir or fault slippage pressures. The addi tional pressure could also affect a given caprock’s abili ty to prevent CO2 or other reservoir fluid leakage through it, as pressure appr oaches or exceeds the capillary entry pressure for the caprock. Finally, the larger volumes of CO2 injected could lead to CO2 or reservoir fluids approach ing of breaching spill points in the reservoir, and/or a greater volume of di splaced fluids and a larger area of elevated pressure.

Similar considerations prevent wells regulated under other existing UIC classifications from being tr eated as GS activities.

3For all of these reasons, we oppose any appr oach that allows we lls that are not subject to the necessary requirements to be defined and treated as GS activities. All CO2 injecti on activities that are treate d under EPA rules as GS projects to protect USDWs and to preven t releases to the atmosphere, whether conducted solely for GS purposes or for additional purposes, must be reviewed and permitted pursuant to adequate ru les set forth for those injection activities. EPA should promulgate such rules under the current rulemaking for Class VI, taking into account differences in target reservoir types as needed.

Individual Response: EPA believes that injection for the primary purpose of long term storage is sufficiently different from Class II ER opera tions and warrants tailored requirements in order to protect USDWs from endangerment. For exam ple, the volume of CO 2 anticipated to be injected in Class VI wells is significantly great er than for Class II wells. Reservoir pressure conditions will also be different, with Class VI injection operations involving large volumes of CO2 and likely having higher pressure s within their storage formations than Class II ER projects, which may lead to fluid movement that endangers a USDW.

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

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

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

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

The purpose of this rule is not to promot e or incentivize the deployment of GS.

Letter ID: 0272 Comment ID: 24078 Letter Lines: 166 to 213

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

Comment Code: 4110 2.4.1.1 Injection pressure limitations

Comment: C. Pressure management

4[FR p. 43538, §146.88(a)] EPA has proposed to a dopt an injection pressure limit equal to 90 percent of the fracture pressure in the injection zone. This is a high number, and there will be cases wher e it is prudent to lower limits. Since injection is likely to take place in diverse geologic settings, we believe that

those limits should be calculated indi vidually, taking into account a number of geologic factors each time, which we atte mpt to incorporate in the proposed language below. Nonetheless, we believe that EPA should maintain a maximum upper limit (equal to or less than 90 percent of the fracture pressure in the injection zone), so as to avoid cases where studies might appear to support higher limits that would not be advisable. We also consider the "Except during stimulation" qualifier as confusing and cr eating a loophole and we urge that it be removed. Finally, the pressure limits themselves should refer to the confining zone and not the injection zone. We offer the following language as a starting point:

"The owner or operator must ensure that injection pressure does not exceed [90] percent of the fracture pressure of the confining zone. The owner or operator must comply with a maximum injection pre ssure limit approved by the Director and specified in the permit. In approving a ma ximum injection pressure limit, the

Director must consider the results of well tests and, wh ere appropriate geomechanical or other studies, that a ssess the risks of tensile failure and

shear failure. Limits shall be calculated so as to assure that pressure will avoid initiation or propagation of fractu res in the confining zone or cause

otherwise non-transmissive faults trans ecting the confining zone to become transmissible. In no case may injection pre ssure cause movement of injection or formation fluids that endangers a USDW."

The maximum upper limit should not be used as a default in place of tests and

studies that should be used to establish appropriate li mits for specific sites - we urge EPA to ensure that this is built into the rule language. The

consideration of both tensile and shear failure is nece ssary in carrying out a rigorous evaluation, in our view, as is th e requirement not to cause otherwise non-transmissive faults transecting the conf ining zone to become transmissible. We also urge EPA to compile a list of quality criteria against which the results

of the mentioned tests and studies will be evaluated - these need to be transparent and capable of screening ad equate tests from inadequate ones.

Pressure limits should also ensure that no significant risks from seismicity are posed, and EPA should incorporate appropr iate language in the setting of pressure limits.

We further believe that the established phras ing "so as to assure that", used in Class II, is preferable to other formula tions such as "with a reasonable degree of certainty". We also belie ve that the proposed rule’s language on movement of fluids "that endangers a USDW" is more pr otective and preferable to the wording "into a USDW", and preferable to refere nces to §144.12(a). As mentioned above, the rule should be drafted to assure no releases to the atmosphere as well.

5Individual Response: EPA disagrees with the s uggestion that injection pr essure be set at less than 90 percent of fracture pressure. EPA believe s that a lower pressure limitation may not allow

for sufficient volumes of CO2 to be transmitte d away from the well and into the injection formation. EPA acknowledges that there may be ci rcumstances where a lo wer pressure limitation may be appropriate; in such cases, the Direct or has the authority, at §146.88, to set a lower pressure limit in the operating permit. EPA believes that the 90 percent requirement allows the consideration of site-specific ci rcumstances and provides a satisfa ctory margin of safety during well operation.

EPA clarifies that injection pressure limit fo r each GS project will be based on site-specific conditions, and be informed by data on the injec tion and confining zones. During injection, the pressure in the injection zone must not exceed 90 percent of the fracture pressure of the injection zone, as specified at §146.88(a). The fracture pressu re (and, therefore, the injection pressure) are based on site-specific geologic and geomechanical data collected during the site characterization process required at §146.82. Tests ar e available and have been used by injection well operators, e.g., Class I operators, to measure fracture pressu re. Examples include the step-rate test, in-situ stress tests, and a combination of a long spaced sonic log with laborat ory measurement of the mechanical properties of cores. To meet the GS requirements, the permitting authority must set the injection pressure limit at 90 percent of this value.

The Director will review geologic, hydrogeolog ic, and geomechanical information submitted by the owner or operator in setting permit conditions. If, based on this information, a lower pressure limitation is appropriate, the Director has the au thority to set a lower limit in the operating permit. EPA clarifies that fracturing of the confin ing zone during injection and/or stimulation is also prohibited at §146.88(a).

The final rule provides for the use of stimulation. EPA believes that stimulation is important for enhancing formation injectivity, provided it is performed in a manner that maintains the integrity of the confining zone. All stimulation must be approved by the Director . Owners or operators must submit a proposed stimulation program as part of the permit application under §146.82(a)(9); the plan must demonstrate that any stimulation activities will not compromise the integrity of the confining zone. The Director wi ll evaluate the owner or operator's proposed stimulation plan in the context of all information about the site , and the owner or operator must perform stimulation only as approved.

EPA is developing guidance on site characterization for GS projects to assist owners or operators in meeting the requirements of §146.82 and to assist directors in evaluating permit applications. The guidance will describe recommended approach es for characterizing the regional geology and hydrogeology of a proposed site and performing the necessary geochemical, geomechanical, and geophysical analyses of the injection and confin ing zone. EPA is also developing guidance for primacy agencies that will include recommended a pproaches for evaluating owner or operatorsubmitted data in setting permit conditions. The gu idance will be available on EPA's web site, at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

6Letter ID: 0272 Comment ID: 24079 Letter Lines: 215 to 271

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

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

Comment: D. Closure

[FR p. 43540, §146.93(b)] EPA has proposed an arrangement where by the operator

continues to monitor the site for a minimu m of 50 years after the cessation of injection, unless the operato r can demonstrate to th e satisfaction of the Director that the project no longer poses an endangerment to USDWs and that the CO2 plume and pressure fr ont have stabilized.

While 50 years is not a number that will apply in all cases and projects, we do believe that it is appropriate as a default at today’s level of our understanding and operational experience with GS. The option that operators have under the current proposal to obtain approval for a lower number, based on actual project performance, should be suffi cient to deal with situations where 50 years can be demonstrated to be u nnecessarily long. Along the same lines, there might be situations where 50 years would not suffice, and where the Director should require a longer perio d, as per the current proposal. In assessing non-endangerment to USDWs and pl ume/pressure front stabilization, we believe that the EPA should be far more sp ecific in its requirements. We offer the following language as a suggested revision to §146.93(b):

"(b) The owner or operator shall monito r the site following the cessation of injection.

(1) The owner or operator shall continue to conduct monitoring as specified in the Director-approved post-injection site care and site closure plan for at least 50 years following the cessation of injection or unt il closure is

authorized.

(2)If the owner or operator can demonstrat e to the satisfaction of the Director before 50 years, based on/pursuant to th e criteria in (b), that the geologic sequestration project does not and is not expected to pose an endangerment to

USDWs or result in releases to the atmo sphere, the Director may approve an amendment to the post-injection site care and site closure pl an to reduce the frequency of monitoring or may authorize si te closure before th e end of the 50- year period.

(3) Prior to authorization for site cl osure, the owner or operator must demonstrate to the Director, based on m onitoring, other site-specific data, and modeling that is consistent with site pe rformance, that no additional monitoring is needed to assure that the geologic se questration project do es not and is not expected to pose an endangerment to USDWs or any release to the atmosphere. The

7owner or operator must demonstrate, ba sed on the current unde rstanding of the site, including monitoring data and modeling, all of the following: (i) the magnitude and extent of the project f ootprint (CO2 plume and the area of elevated pressure); (ii) th e location of the detectable CO2 plume; (iii) that there is no significant leakage of either CO 2 or displaced formation fluids that is endangering USDWs or creating a potenti al release to the atmosphere; (iv) that the injected or displaced fluids are not expected to migrate in the future in a manner that encounters a potential leak age pathway into a USDW or to the atmosphere; (v) that the injection wells at the site completed into or through the injection zone or confining zone ar e plugged and abandoned in accordance with these requirements; a nd (vi) any remaining projec t monitoring wells at the site are being managed by a person and in a manner acceptable to the Director.

(4) If such a demonstration cannot be ma de after the 50-year period, the owner or operator must submit to the Director a plan to continue po st-injection site

care."

Individual Response: EPA agrees that a 50 year post-injec tion site care timeframe represents a reasonable and protective post-inje ction site monitoring period fo r most projects and available data, including data submitted by commenters, do not support a different default timeframe. EPA bases this on a review of research studies, i ndustry reports, and existing environmental programs, and evaluation of public comments.

However, EPA recognizes that there may be site s where the 50 year post injection site care timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. For this reason, the GS rule o ffers owners or operators flexibility regarding

the duration of the PISC timefra me by: (1) allowing the Direct or discretion to shorten or lengthen the PISC timeframe during the post-in jection period based on site-specific data, pursuant to requirements at §146.93(b) ; or (2) affording the Director discretion to allow a Class VI well owner or operator to demonstrate, during the permitting process based on substantial data, that an alternative PISC timeframe may be appropriate if it ensu res non-endangerment of USDWs pursuant to requirements at §146.93(c).

EPA believes however, that to ensure USDW protection from enda ngerment, a default timeframe for post-injection site care will be necessary in most cases. The default 50 year post-injection site care timeframe represents a reasonable and prot ective monitoring period based on a review of research studies, industry reports, and existing environmental programs, and evaluation of public

comments.

EPA believes that a default post-injection site car e timeframe of 50 years, with flexibility to adjust the timeframe for a limited number of GS projects during the permitting process where

substantial data exists to demonstrate that an alternative timeframe would be protective of USDWs, or based on data collected during the PISC period, is appropriate to address the range of sites where GS is anticipated to occur, to ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-specific data, and be based on pressure monitoring and USDW

8impacts.

In response to comments to be more specific, EPA believes §146.93 is suffi ciently specific for the purposes of protecting USDW s. Furthermore, the commenter’s proposed language regarding

released CO2 emissions into the air are outside the scope of this rulemaking and EPA’s authority

under the SDWA.

Letter ID: 0272 Comment ID: 24080 Letter Lines: 274 to 285

Comment Code: 5460 2.9.2 Comments on transfer of lia bility for long-term care

Comment: In addition, given the desired permanent nature of CO2 sequ estration in the subsurface and the importance to the public of ensuring long-term attention to oversight of project sites, EPA should a dopt provisions to assure long-term stewardship of GS repositories. This fram ework should designate an entity with responsibility for monitoring and mana ging sites after closure has been authorized. The proposed rule authorizes operators to stop monitoring, but does not provide for the stewardship of sites following closure. This needs to be rectified by EPA. The agency should consid er its authority not just under the Safe Drinking Water Act, but also unde r the Clean Air Act to provide the required stewardship framework. It is impor tant that the post-closure framework include financing provisions that avoi d hidden subsidies for private sector operators and are adequate to ensure proper site stewar dship in the long-term.

Individual Response: Once an owner or operator has met all regulatory requirements under Part 146 for Class VI wells and the Director has appr oved site closure pursuant to requirements at §146.93, the owner or operator will generally no l onger be subject to enforcement for regulatory noncompliance. Furthermore, the financial inst rument required under §146.85 will be released if it has not been used. However, even if a site closure is approved under §146.93, an owner or operator may be held liable for regulatory noncompliance (includi ng violation of 40 CFR 144.12) in certain circumstances, for example, if the Director relied on erroneous information provided by the owner or operator when approving site closure. Additionally, an owner or operator may always be subject to any action the Administrator deems necessary to protect the health of persons under §1431 of the SDWA after s ite closure if there is unanticipated migration

towards or into a USDW that causes or threat ens imminent and substantial endangerment to public health. The action may include issuing administrative orders or commencing a civil action for appropriate relief. If the owner or operator fail s to comply with the order, they may be subject to a civil penalty for each day in which such vi olation occurs or failure to comply continues.

The Agency clarifies that Class VI well permits may be transferred to another owner or operator pursuant to §144.38, whereby all othe r regulatory respons ibilities are transf erred, including all potential liabilities associ ated with meeting the requirements of that permit. Please see further

clarification on the i ssue of long term liab ility in the preamble of the final rule.

After site closure an owner or operator may remain liable under tort and other remedies, or under

other federal statutes includi ng Clean Air Act, 42 U.S.C. §§ 7401-7671; CERCLA, 42 U.S.C. §

910 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. EPA does not have authority to transfer SDWA or other legal liability for Class VI wells to th e State or federal government or a third-party fund. See the final rule preamble for furt her discussion of EPA's approach.

Comments related to EPA’s authority under the Cl ean Air Act are outside the scope of the GS regulation.