2.3

– Responses to Public Comments on Injection Well Construction

This file contains responses to public comments on injection well construction ( c omment codes 3800 to 3866 ). This section i ncludes comments on requirements for surface and long

- string casing, tubing and packer, horizontal drilling techniques, use of corrosion resistant materials, and pre

- injection logging and testing

.

The table below presents all of the EPA

- assigned comment codes that are inclu ded in

this section of the comment and response summary . Use the bookmarks in the PDF to move among the comment codes

.

Topics included in this summary and associated comment codes

Topic Code
2.3 Proposed Injection Well Construction Requirements (40 CFR 146.86) 3800
2.3.1 Well construction procedures 3820
2.3.1.1 Depth of surface casing 3822
2.3.1.2 Cementing of long

- string casing 3824
2.3.1.3 Packer requirements 3826
2.3.2 Horizontal well drilling techniques 3840
2.3.3 Well component degradation 3860

2.3.3.1 Use of corrosion

- resistant construction materials 3862

2.3.3.2 Use of corrosion

- resistant cements 3864
2.3.3.3 Logging and testing requirements (40 CFR 146.87) 3866

Every comment on these topic areas and the associated response is included in this summary; there is some repetition where multiple commenters made the same

comment.

R esponses to letters from individual commenters or organizations are also available in

the rulemaking docket.Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 146.86)



### Individual Comments

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22519 Other EPA Comment Codes and Descriptions: 1340 1.1.3.2 Oppose use of GS in general; 5000 2.8 Proposed Well Plugging and Post-Injection Site Care Requirements
Comment: passing a written examination. Further, the Agency proposes to sequester buoyant CO2 until the end-of-time by only requiring 50 years of monitoring (40 CFR 146.93(b)(1)). In addition, EPA proposes using well completion materials not currently developed and proven corrosion-resistant under carbonic acid
corrosive conditions.

The proposed regulations are a formula for future disaster: 1) Dangerous to sequester CO2, a supercritical fluid stored at high pressure (2200± psi): 2)

Response: EPA does not believe that a properly managed GS site is dangerous. The Class VI GS regulation builds upon the long-standing protective framework of the UIC program, which has been regulating the injection of billions of gallons of liquids for decades. The Class VI GS regulation enhances this existing framework with requirements for Class VI wells that are tailored to the unique nature of large scale GS of CO2.

EPA believes that a 50 year post-injection site care timeframe represents a reasonable and protective post-injection site monitoring period for most GS 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, industry reports, and existing environmental programs, and evaluation of public comments. EPA adds that the GS regulation includes a provision that the Director may, at their lengthen the post-injection site care timeframe if the owner or operator cannot demonstrate that movement of the plume and pressure front have ceased and the injectate does not pose a risk to USDWs (146.93(b)(2)).

EPA disagrees that corrosion-resistant materials and cement do not exist. Industry experience of many decades in corrosive down-hole situations such as acid gas injection and production of natural gas with carbon dioxide and hydrogen sulfide impurities shows that materials are available that can resist corrosive environments. Meyer (2007) lists several types of cements that have been used under such corrosive conditions. EPA acknowledges that studies have likely not been performed to prove a 50-year life span for corrosion-resistant materials. However, there are two studies of wells that were exposed to CO2 for approximately 30 years by Carey et al. (2007) and Crow et al. (2008). Although these studies are limited in the number of well material samples and the number of wells examined, the casing and cement sampled indicate fairly good condition (i.e., fairly significant corrosion resistance) of well materials installed three decades ago. The best available corrosion-resistant materials suited for each GS project will be determined by the Director.

EPA adds that, to address potential risks associated with high pressures associated with CO2 injection for GS, the final rule, at §146.88(e)(2), requires that owners or operators of onshore Class VI wells install automatic surface shut-off devices. Owners or operators must also monitor pressure in the injection zone, as required at §146.90(g).EPA acknowledges that there are limited data on this subject, and believes that providing multiple barriers of protection is the most appropriate approach to protecting USDWs from endangerment. 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.

The Agency plans to, every six years, collect and review project data on early GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22526 Other EPA Comment Codes and Descriptions: 1450 1.2.2.1 Oppose the GS rulemaking
Comment: e.g., without EPA specifications, except longevity of materials, e.g., corrosion resistance requirements, etc., EPA PLACES THE RESPONSIBILITY ON AN INDUSTRY WHICH GOVERNMENT, THE PUBLIC AND REGULATORS HAVE NEVER TRUSTED, BRYANT (2007).

THE PROPOSED RULE MUST BE WITHDRAWN!

Bryant, S., 2007. Geologic CO2 Storage - Can the Oil and Gas Industry Help Save the Planet? J Pet. Tech (JPT), p 98-105, September

Response: EPA disagrees that the final GS rulemaking provides industry with the responsibility to enforce GS requirements. EPA clarifies that responsibility for enforcing the GS rule rests with state and/or regional permitting authorities, not industry, and that states seeking to implement the GS rule must demonstrate in their primacy program submission that they will implement a program that is at least as stringent as the federal requirements for permitting, site characterization, monitoring, and site closure, as well as for all other GS rule requirements as required under §1422 of SDWA.

The prescribed construction requirements described in the final GS rule for Class VI wells are sufficient to protect USDWs from endangerment. EPA adds that the requirement at §146.86(b)(1) that materials must meet or exceed standards developed by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director invokes the expertise of these bodies which, combined with the review by the Director of all site-specific information required to be submitted at §146.82(a) will ensure that the owner or operator constructs a well that will ensure USDWs are protected from endangerment. EPA believes that permitting authorities, which have many staff who have been overseeing UIC programs for decades, have sufficient expertise to evaluate the appropriateness of cements for use in specific situations.

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. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for

additional information.

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22530Other EPA Comment Codes and Descriptions: 1670 1.3.7 Other/miscellaneous risks
Comment: The mixture of hazardous wastes associated with Class I injection wells do not aggressively attack carbon steel or cement. Also, hazardous waste will not change phase, as supercritical CO2 does when the pressure is decreased. The change in fluid phase results in formation of a gas, which is large in volume and more redily able to find its way to the surface of the earth through minute cracks. The earth’s surface is full of examples of oil seeps, e.g., the underwater seeks at Santa Barbara, California, and oil seeps in and around the Pennsylvania oil fields, to name a few areas where leaks are known to occur.

The hazardous wastes stored in Class I wells are retained underground because, the column of waste formed when a leak occurs, provides a controlling head of weighted fluid. In the case of CO2 the hydraulic head, in the event of a leak, becomes less as the over burden pressure reduces. This is a much more dangerous condition than experienced with Class I wells.

Class II enhanced oil recovery (EOR) wells are not abandoned with a high residual head of buoyant gas. Typically, the well is produced until the field becomes un-economical (too depleted) to produce. This, unlike the CO2 sequestration wells is not under high supercritical pressure (2200 psig pressure) at the time of abandonment. Also, a Class II CO2 injection well is associated with oil producing operations, which can be protected from corrosion by injecting corrosion inhibitor into the producing well during the producing phase.

Response: EPA believes that the construction requirements at §146.86 provide an appropriate level of protection from endangerment to USDWs that is based upon the existing UIC framework for deep wells. The new tailored approach was designed to address the general risks deep injection may pose to USDWs and was tailored specifically to address the unique nature of CO2 GS (i.e., 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 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 believes that building upon the existing UIC requirements (e.g., Class I and Class II well requirements) to develop the Class VI GS regulation provides a foundation for protecting USDWs based on success, field experience, and lessons learned about CO2 injection in other applications. Class I well owners or operators have experience with site characterization, well construction, and monitoring procedures and technologies that are applicable to Class VI wells. Class II ER well operators have experience with managing the unique properties of CO2. To successfully flood a hydrocarbon field with CO2 during an ER operation, the behavior of injected CO2 must be well

understood.Commenter Name: Iain Wright Letter ID: 0118 Commenter Organization: BP Alternative Energy Comment ID: 22066 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: At In Salah, a few miles up-dip from the three CO2 injectors, we have four wells that produce natural gas from the same geological formation. The design of the CO2 injectors is identical to the design of the gas producers except that the gas producers have stainless steel tubing, whereas the CO2 injectors have conventional mild steel (L80) tubing. This is because the gas producers are actually in a more corrosive environment than the CO2 injectors. So, just to emphasize that point: the CO2 sequestration wells, permitted at In Salah are constructed to a lower specification than the natural gas wells in the same
formation. WE RECOMMEND THAT THE DESIGN AND CONSTRUCTION OF GEOSEQUESTRATION

WELLS SHOULD BE SITE-SPECIFIC AND FIT FOR THE PURPOSE OF PREVENTING

ENDANGERMENT

OF USDWS.

Response: EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility regarding appropriate materials for 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). The Director will evaluate the owner or operator's proposed construction procedures, including materials to be used, in the context of information about the well, the CO2 stream, and the site, as specified in §146.86(b)(1). EPA is aware of GS efforts at In Salah and clarifies that the wells in question were not constructed in accordance with U.S. regulations, so the comparison is not necessarily analogous. A paper summarizing EPA's review of In Salah and other large international GS projects is in the rulemaking docket.

Commenter Name: Leslie Savage Letter ID: 0122 Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24781 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: §146.86 Injection well construction requirements. (a) General. The owner or operator must ensure that all Class VI wells are constructed and completed to:

(1) Prevent the ENDANGERMENT OF USDWs movement of fluids into or between USDWs or into any unauthorized zones ; (2) Permit the use of appropriate testing devices and workover tools; and (3) Permit continuous monitoring of the annulus space between the injection tubing and long string casing.

Response: EPA disagrees with the suggested edit. EPA believes that protection of USDWs from endangerment and prevention of fluid movement between formations is paramount, and believes that the language as proposed regarding preventing fluid movement is more specific and protective. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of therequirements for construction and pre-operational testing of Class VI wells at §§146.86 and 146.87.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24125
Comment: Class VI Well Construction and Operation

EPA should also reconsider its proposed well construction and operation requirements which are much more prescriptive and rigorous than necessary and do not reflect industry's 35-plus years of demonstrated success in injecting CO2 under the Class II UIC program. The buoyancy, corrosiveness in the presence of water, and anticipated volumes of CO2 do not justify the Class I hazardous well construction and operating requirements that EPA is proposing. The Class II EOR wells constructed for CO2 injection projects - and their operating practices - have an excellent record of mechanical integrity and protecting USDWs. Recent research by the University of Texas, Bureau of Economic Geology presented at the Department of Energy's Regional Partnership meeting in Pittsburgh, PA in October 2008 demonstrates that 35 years of CO2 injection operations at the SACROC field in Texas have not impacted the USDWs in the area.

Furthermore, some of the proposed requirements - such as cementing the long string casing to surface and use of down-hole shut-off valves - are not only unnecessarily burdensome, but might also interfere with operations, may not serve their intended purpose, and could introduce unintended risks. For example, cementing the longstring casing to surface seals off access to the annulus which could otherwise be used to monitor subsurface formations for potential leakage.

Response: EPA disagrees that the well construction standards for Class VI wells are too stringent. Instead, the construction requirements at §146.86 provide an appropriate and necessary level of protection from endangerment to USDWs that is based upon the existing UIC framework for deep wells. The new tailored approach was designed to address the general risks deep injection may pose to USDWs and was tailored specifically to address the unique nature of CO2 GS (i.e., 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 adds that promoting GS or carbon management efforts is outside the scope of the GS rulemaking, which focuses on protecting USDWs from endangerment.

EPA does not believe that the cementing requirements at §146.86 would prevent annulus monitoring. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24170Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(a)(1)

API Comments: (1) Prevent the movement of fluid into or between USDWs or into any unauthorized zones; CONTAINING ANY CONTAMINANT INTO USDWS, IF THE

PRESENCE

OF THAT CONTAMINANT MAY CAUSE A VIOLATION OF ANY PRIMARY DRINKING

WATER

REGULATION UNDER 40 CFR PART 142 OR MAY OTHERWISE ADVERSELY AFFECT

THE HEALTH OF PERSONS.;

Rationale: The proposed changes reflect the nonendangerment standard that is the basis of the UIC program.

Response: EPA disagrees that the proposed language provided in §146.86 does not reflect the nonendangerment standard as required under the SDWA. EPA believes that protection of USDWs from endangerment and prevention of fluid movement between formations is paramount and the language as proposed meets the non-endangerment standard, therefore it is not necessary to make such edits. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of the requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 146.87.

Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment EPA has made many revisions to the GS rule. Please see the final rule and preamble for additional information.

Commenter Name: Frederick R. Eames Letter ID: 0178 Commenter Organization: CCS Alliance Comment ID: 23863
Comment: D. INJECTION WELL CONSTRUCTION REQUIREMENTS

Well construction procedures and requirements should remain reasonable and flexible given that long-term CO2 storage remains a relatively new area with developing science and technologies. The experience of the operator, the volume of CO2 stored, and the pressure at which it needs to be injected, should be viewed as important variables when finalizing well construction requirements. EPA also should consider that a properly installed well provides a barrier to fluid movement, even if components are shown to degrade in aggressive laboratory experiments. It is also not known if new CO2 resistant cements will perform as

Response: EPA agrees that a flexible approach to the construction of Class VI wells is appropriate, and believes the rule provides an appropriate amount of flexibility. The construction requirements at §146.86 provide flexibility by listing the basic components a Class VI well must have to prevent endangerment of USDWs, and allow owners or operators to choose appropriate materials in meeting these requirements.

Commenter Name: Thomas Curtis Letter ID: 0181Commenter Organization: American Water Works Association (AWWA) Comment ID: 23722 Other EPA Comment Codes and Descriptions: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)
Comment: Part 146.81(c) Specific benchmarks should be established to demonstrate that USDWs will not be endangered if the well is exempted from the casing and cementing requirements provided in Parts 146.86(b) and 146.87(a)(1) through (3). This will provide for a consistent application of this requirement across each permitting agency.

Response: EPA believes that, given the range of types of existing wells that may be candidates for conversion, flexibility is appropriate regarding conversion of Class I, II, or V wells for GS, provided
it can be demonstrated to the Director's satisfaction that the converted well can conduct Class VI operations in a manner that does not endanger USDWs. The final GS rule, at §146.81(c), allows the construction of these wells to be grandfathered, 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 is developing guidance documents that will support UIC Directors in evaluating whether grandfathering specific wells is appropriate. For example, primacy guidance for primacy agencies will describe areas of Director’s discretion and recommended procedures and considerations for exercising that discretion. EPA is also developing guidance on construction of Class VI wells. The guidances will be available on EPA's web site at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Thomas Curtis Letter ID: 0181 Commenter Organization: American Water Works Association (AWWA) Comment ID: 23735 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Part 146.86(b)(1) AWWA recommends revising the second to the last sentence to

read:

The casing and cementing program must be designed to prevent the movement of fluids into or between USDWs and between the injection zone(s) and USDWs.

Response: EPA believes that the existing language as written ensures the prohibition of fluid movement between the injection zone and any USDW and the suggested change is unnecessary. Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment EPA has made many revisions to the GS rule. Please see the final rule and preamble for additional information.

Commenter Name: Thomas Curtis Letter ID: 0181 Commenter Organization: American Water Works Association (AWWA) Comment ID: 24376 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Part 146.86(b)(1)(i) AWWA recommends revising this part to read:

Depth to the injection zone and overburden pressures in the injection zone.Response: EPA believes that the requirement in 146.86(b)(ii) to report the external pressure provides the same information as the requested change. Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment EPA has made many revisions to the GS rule. Please see the final rule and preamble for additional information.

Commenter Name: Wendy Jacobs Letter ID: 0183 Commenter Organization: Harvard Law School Environmental Law and Policy

Center Comment ID:

25139 Other EPA Comment Codes and Descriptions: 1210 1.1.1 Comments about the proposed rule
Comment: ELPC and ETIP commend EPA for including precautionary measures for Class VI wells above and beyond what is required for other classes of wells. The proposed regulation allows the owner or operator the flexibility to choose particular cements or metal well components for Class VI wells while still requiring that such materials meet or exceed the standards developed by the American Petroleum Institute, ASTM International or comparable standards acceptable to the Director. 73 Fed. Reg. at 43,537 (proposed 40 C.F.R. § 146.86(b)(1)). By doing so, the proposed regulation addresses the potential corrosion of cement and metal well components by the CO2 stream (plus water impurities) that can compromise the structure of the well and result in leaks of stored CO2. ELPC and ETIP laud other precautionary measures required in the proposed regulation, including down-hole shut off valves, continuous and frequent monitoring of the integrity of the internal and external portions of the well, tracking the plume and pressure front, and detailed electronic record keeping. Id. at 43,511, 43,538-40 (proposed 40 C.F.R. §§ 146.88-.91). The requirements in the proposed regulation reflect EPA’s understanding of and sensitivity to the challenges posed by CCS. Because CO2 GS entails new technology with a potentially large impact and lasting duration, ELPC and ETIP support these precautionary measures.

Response: EPA acknowledges the comment and agrees that protection of USDWs from endangerment and prevention of fluid movement between formations is paramount. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of the requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 146.87.

Please see the remainder of EPA's responses to this comment and the final rule and preamble for

further details.

Commenter Name: Bradley J. Field Letter ID: 0186 Commenter Organization: New York State Dept. of Environmental Conservation
Div. of Mineral Resources Comment ID:

25186
Comment: O. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval.

NYSDEC-DMN Response: NYSDEC-DMN agrees with the need for adequate protection of USDWs and the proposed measures. However, Director discretion may be necessary to address site-specific conditions and the Director should be able to grantwaivers to any requirement provided it can be demonstrated that such will not endanger USDWs.

Response: EPA agrees that a flexible approach to the construction of Class VI wells is appropriate, and believes the rule provides an appropriate amount of flexibility. The construction requirements at §146.86 provide flexibility by listing the basic components a Class VI well must have to prevent endangerment of USDWs, and allow owners or operators to choose appropriate materials in meeting these requirements. However, EPA notes that the Director may not waive any construction requirement unless the regulation specifically gives the Director such discretion for a particular requirement (e.g., §146.83(b)(4) allows the Director to approve alternative methods of cementing in some circumstances).

The Director will evaluate the appropriateness of the proposed well construction based on sitespecific information about the injection project, including injection pressures, injection and confining zone lithology, and information about the carbon dioxide stream as provided in §146.86(b)(1). 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.

Commenter Name: Bradley J. Field Letter ID: 0186 Commenter Organization: New York State Dept. of Environmental Conservation
Div. of Mineral Resources Comment ID:

25187 Other EPA Comment Codes and Descriptions: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment)
Comment: P. EPA also seeks comment on how the proposed grandfathering provisions for existing wells (construction requirements) may affect compliance with the above, proposed construction requirements.

NYSDEC-DMN Response: NYSDEC-DMN believes that Director discretion is appropriate and necessary when reviewing other UIC Class wells for use as UIC Class VI wells. Overly prescriptive well construction requirements without any mechanism for deviation may limit the use of existing UIC wells and possible sequestration

sites.

Response: As described above, conversion of the well would be at the Director's discretion following an evaluation of all other site-specific information about the well and the project, e.g., modeling, monitoring, and other data. Any wells that have deteriorated due to contact with incompatible injected or formation fluids may not be approved for conversion.

EPA believes that, given the range of types of existing wells that may be candidates for conversion, flexibility is appropriate regarding conversion of Class I, II, or V wells for GS, provided it can be demonstrated to the Director's satisfaction that the converted well can conduct GS operations in a manner that does not endanger USDWs. The final GS rule, at §146.81(c), allows the construction of these wells to be grandfathered, 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 ensureprotection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). Only the cemented-inplace construction requirements would be grandfathered under the final GS rule; following conversion, these wells must be permitted as Class VI wells and be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final
GS rule.Furthermore, EPA is developing guidance on transitioning from Class II to Class VI. The guidance will assist Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI transition. The guidance describes the methods available for the Director to determine the risk posed to USDWs from a GS/ER project, and how the Director may determine if a project should be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Daniel Plath Letter ID: 0188 Commenter Organization: NiSource, Inc. Comment ID: 25229 Other EPA Comment Codes and Descriptions: 1610 1.3.1 Risks to USDWs; 3400 2.2.2 Corrective Action; 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 146.92)
Comment: aspects. The following points summarize four primary lessons learned through operation of natural gas storage that would be applicable to GS:

1. History has shown that the one component in the system that has caused the most safety issues is the wells; specifically the operator's wells, plugged and abandoned (P&A) wells and third party operating wells (e.g. oil and gas production wells). The casing and cement in the storage well is the "first line of defense" in the containment of high pressure gas and a properly designed,
constructed and maintained well is critical. Even after several decades of operations over a four State area, NiSource subsidiaries have never experienced loss of containment from cap rock leakage, migration up faults, re-activation of faults, earthquakes, or the other potential leakage pathways that EPA discusses in the Proposed Rule. While history will ultimately reveal the root causes of future problems, if any, with GS, NiSource submits that the predominant cause will likely be identified as being related to an active well, abandoned well or third party well if not properly addressed in the Final Rule. This is based on the belief that the rigorous site selection process will preclude the other sites that would have had other issues, e.g. cap rock leakage, from even being activated in the first place.

Response: EPA agrees that proper site characterization should minimize leakage through faults, breaks in the seal of the confining layer, and other geologic pathways. EPA believes that the construction, operating, and monitoring requirements in the GS rule will prevent leakage from occurring through active wells. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of the requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 146.87.

EPA also agrees that the AoR and corrective action process should identify both abandoned wells and third party wells that could serve as leakage pathways. The UIC Program's long-standing approach to corrective action, tailored to the potential corrosivity of and impurities in the CO2 stream, can address the potential risk associated with improperly plugged wells in the AoR.

EPA notes that the final rule, at 40 CFR §124.10(c)(1)(xi), requires the notification of state oil and gas agencies, state mineral exploration agencies, and state public water supply supervision directors about the availability of the draft permit . EPA expects that such notification can help with further identifying wells in the area of review.Commenter Name: Daniel Plath Letter ID: 0188 Commenter Organization: NiSource, Inc. Comment ID: 25233 Other EPA Comment Codes and Descriptions: 3400 2.2.2 Corrective Action
Comment: The Proposed Rule adequately addresses the issues of well construction requirements and the review of existing plugged and abandoned wells. Specifically, Section 146.86 would have sufficient number of cemented strings of pipe in the well while Section 146.84 would ensure that abandoned wells are properly plugged.

Response: EPA acknowledges the comment and agrees that the requirement for long-string casing of Class VI wells at §146.86(b) will offer the best protection against fluid movement behind the casing, between formations, and above the injection zone and will ensure competency of Class VI wells and protect USDWs from endangerment. The buoyant nature of CO2 dictates deep well construction procedures that address movement of fluid behind the casing and provide necessary barriers to CO2 leakage outside of the injection zone. In developing the construction requirements for Class VI wells, EPA reviewed the work cited by Carey et al. (2007) and Crow et al. (2008). EPA believes that they offer important justification for the establishment of tailored requirements.

EPA agrees that corrective action as required at §146.84(d) is an important part of preventingendangerment of USDWs from CO2 or associated fluids. EPA believes that the UIC Program's longstanding approach to corrective action, tailored to the potential corrosivity, and impurities in the CO2 stream, can address the potential risk associated with improperly plugged wells in the AoR.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24443 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(a)(1)

Proposed CCS Group Recommendations: (1) Prevent the movement of fluid into or between USDWs or into any unauthorized zones; CONTAINING ANY CONTAMINANT INTO USDWS, IF THE PRESENCE OF THAT CONTAMINANT MAY CAUSE A VIOLATION OF

ANY PRIMARY

DRINKING WATER REGULATION UNDER 40 CFR PART 142 OR MAY OTHERWISE

ADVERSELY AFFECT THE HEALTH OF PERSONS;

Basis for CCS Group Comments: The proposed changes follow the non-endangerment standard that is the basis of the UIC program.

Response: EPA disagrees that §146.86 as written does not meet the non-endangerment standard as required under the SDWA. EPA believes that protection of USDWs from endangerment and prevention of fluid movement between formations is paramount and believes that the language as proposed meets the non-endangerment standard. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout thelifetime of a GS project. This is the foundation of the requirements for construction and preoperational testing of Class VI wells at §§146.86 and 146.87.Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. Please see the final rule and preamble for additional information.

Commenter Name: Jeff W. Sheets Letter ID: 0192 Commenter Organization: ConocoPhillips Comment ID: 23894
Comment: Well Standards:

Some well standards, as written in the proposed rule, seem to build from Class I Hazardous requirements, which is a level of rigor not necessary for protection of USDWs in all C02 injection sites. Given oil and gas industry experience with Class II wells, the non-hazardous nature of CO2, and benefits of considering many types of sites, geological formations, and confining configurations, we
recommend increased consideration for Class II influence in Class VI well standards. Given that all UIC injection well classes are designed to protect USDWs, ConocoPhillips supports API recommendations, and believe the following are particularly important:

Response: EPA disagrees that the well standards provided in the GS rule are too rigorous for all Class VI wells. Although the requirements are based on the existing regulatory framework for deep wells, including Class I wells, EPA believes that GS is sufficiently different from other injection operations to warrant the tailored requirements for Class VI wells at §146.86. The well construction requirements are necessary to protect USDWs from endangerment.

Furthermore, EPA clarifies that the requirements for Class VI wells are not necessarily more stringent than those for Class I hazardous waste injection wells, rather they are different. For example, Class I hazardous well owner or operators are subject to requirements that are not applicable to Class VI wells, such as no migration petitions.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24566
Comment: The majority of the well construction and operating requirements appear to be built on the Class I Hazardous Waste program. Based on industry's excellent environmental and safety record with CO2 injection practices, Anadarko recommends the EPA reconsider the proposed regulations. Several misconceptions on well design have been recently addressed as further. research has been completed in the field. One of these misconceptions is the cementing

Response: Although the requirements are based on the existing regulatory framework for deep wells, including Class I wells, EPA believes that GS is sufficiently different from other injection operations to warrant the tailored requirements for Class VI wells at §146.86 in order to protect USDWs from endangerment.

EPA clarifies that the requirements for Class VI wells are not necessarily more stringent than those for Class I hazardous waste injection wells, rather they are different. For example, Class I hazardous well owners or operators are subject to requirements that are not applicable to Class VI wells, such as no migration petitions.Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24670 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(a)(1)

Anadarko Petroleum Corporation (APC) Comments: (1) Prevent the movement of fluid into or between USDWs or into any unauthorized zones; CONTAINING ANY CONTAMINANT INTO UNDERGROUND SOURCES OF DRINKING WATER, IF THE

PRESENCE OF THAT

CONTAMINANT MAY CAUSE A VIOLATION OF ANY PRIMARY DRINKING WATER

REGULATION UNDER

40 CFR PART 142 OR MAY OTHERWISE ADVERSELY AFFECT THE HEALTH OF PERSONS.;

Rationale: The proposed changes reflect the nonendangerment standard that is the basis of the UIC program.

Response: EPA disagrees that the language provided in § 146.86(a)(1) does not meet the nonendangerment standard provided under the SDWA. In fact, EPA believes that protection of USDWs from endangerment and prevention of fluid movement between formations is paramount and believes that the language as proposed meets the non-endangerment standard. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of the requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 146.87.

Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. Please see the final rule and preamble for additional information.

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23971
Comment: 4. § 146.86 Corrosiveness of the carbon dioxide stream, and formation fluids;

Under the proposed rule, the Director is required to determine and specify casing and cementing requirements to ensure that a proposed Class VI well is constructed and completed to prevent the movement of fluids into or between USDWs or into any unauthorized zones and to permit appropriate testing and monitoring. The proposed rule does not adequately explain or justify the information requirements set forth therein.

EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells.(1)(v) Corrosiveness of the carbon dioxide stream, and formation fluids;

The proposed rule requires an applicant to submit to the Director information on the corrosiveness of the carbon dioxide stream, and formation fluids. Neither the proposed rule nor the Preamable adequately explains whether the information requested is corrosiveness of the combined streams of CO2 and formation fluids, or each independent stream (which seemsunnecessary). Further, the proposed rule or the Preamble should elaborate on what type of data may be acceptable --laboratory data for hypothetical streams, empirical testing, analogous wells? Clarification is requested on the aforementioned requirements.

Response: The GS rule at §146.86(b)(1) requires that all injection well materials be compatible with fluids with which the materials may be expected to come into contact. Further, the rule, at §146.82(a)(7), requires owners or operators to submit information on planned injection pressures, that the Director will use in evaluating the proposed casing, tubing, and packer design. EPA adds that, in determining the suitability of well materials and the design of the well, the Director must consider various aspects of the injection project, including injection pressure, external pressure, internal pressure and axial loading in §146.86(b)(1)(ii), corrosiveness of the CO2 stream, and formation fluids in §146.86(b)(1)(v).

EPA requires under §146.90 that owners or operators submit proposed testing and monitoring plans to the Director at the time of the permit application. The operator will need to demonstrate that the monitoring wells will be constructed and operated in a manner that will be sufficiently protective of USDWs from endangerment. Monitoring wells will differ from injection wells in their intent, casing sizes, and depth, although their casing and cementing will likely be similar. Unlike injection wells, monitoring wells will not need to be built to withstand CO2 injection, but, nonetheless, will need to be built with materials and a design that ensure integrity of the well throughout its planned life so
that the well does not serve as a conduit for movement of the CO2 stream or formation fluids.

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.

Commenter Name: Tiffany Rau Letter ID: 0224 Commenter Organization: Hydrogen Energy International Comment ID: 21673 Other EPA Comment Codes and Descriptions: 4000 2.4 Proposed Injection Well Operating Requirements (40 CFR 146.88)
Comment: (1) Importance of Well Integrity

EPA has appropriately recognized that wells are a fundamental component of a secure system for the long-term geologic sequestration of CO2. As such, applying appropriate well design, construction & operating requirements is critical to the delivery of secure storage. As previously discussed, oil and gas operators have nearly four decades of experience, via past and existing production operations, in constructing and operating CO2 EOR/EGR wells in a safe and secure manner. Notably, Class II requirements have proven to be effective in ensuring the non-endangerment of USDWs. Therefore, HEI believes it would be prudent to rely upon this extensive existing regulatory and industry experience and knowledge in setting Class VI requirements for wells that inject CO2 for long term sequestration.

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced recovery and that many of the wells used for ER may be suitable for GS. However, EPA believes that GS is sufficiently different from Class II ER operations to warrant thetailored construction requirements for Class VI wells at §146.86. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will 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. Therefore, Class VI GS reservoir pressures will increase more in comparison to Class II ER during the injection phase of the GS project.

The final GS rule, at §146.81(c), allows the construction of these wells to be grandfathered, 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). Only the cemented-in-place construction requirements would be grandfathered under the final GS rule; following conversion, these wells must be permitted as Class VI wells and be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final GS rule.

EPA is developing guidance on transitioning from Class II to Class VI. The guidance will assist Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI transition. The guidance describes the methods available for the Director to determine the risk posed to USDWs from a GS/ER project, and how the Director may determine if a project should be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Regarding operational requirements, EPA believes such requirements are necessary for Class VI wells to protect USDWs from endangerment by providing multiple safeguards to ensure that well integrity, containment of fluids within the injection zone, and that the integrity of the confining zone is not compromised. Some of the operating requirements in the GS regulation (e.g., pressure limitations or annulus pressure requirements) are consistent with those for other injection well types, while other requirements (e.g., use of automatic shut-off systems or tracers at the Director's discretion) are tailored to directly address the potential for large volumes of CO2 to be injected, among other factors.

Commenter Name: Brian Williams Letter ID: 0225 Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21718 Other EPA Comment Codes and Descriptions: 4000 2.4 Proposed Injection Well Operating Requirements (40 CFR 146.88)
Comment: (1) Importance of Well Integrity

EPA has appropriately recognized that wells are a fundamental component of a secure system for the long-term geologic sequestration of CO2. As such, applying appropriate well design, construction & operating requirements is critical to the delivery of secure storage. As previously discussed, oil and gas operators have nearly four decades of experience, via past and existing production operations, in constructing and operating CO2 EOR/EGR wells in a safe and secure manner. Notably, Class II requirements have proven to be effective in ensuring the non-endangerment of USDWs. Therefore, BP believes it would be prudent to rely upon this extensive existing regulatory and industry experience and knowledge in setting Class VI requirements for wells that inject CO2 for long term sequestration.Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced recovery and that many of the wells used for ER may be suitable for GS. 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. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will 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. Therefore, Class VI GS reservoir pressures will increase more in comparison to Class II ER during the injection phase of the GS project.

The final GS rule, at §146.81(c), allows the construction of these wells to be grandfathered, 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). Only the cemented-in-place construction requirements would be grandfathered under the final GS rule; following conversion, these wells must be permitted as Class VI wells and be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final GS rule.

EPA is developing guidance on transitioning from Class II to Class VI. The guidance will assist Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI transition. The guidance describes the methods available for the Director to determine the risk posed to USDWs from a GS/ER project, and how the Director may determine if a project should be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Regarding operational requirements, EPA believes such requirements for Class VI wells are necessary to protect USDWs from endangerment by providing multiple safeguards to ensure that well integrity, containment of fluids within the injection zone, and that the integrity of the confining zone is not compromised. Some of the operating requirements in the GS regulation (e.g., pressure limitations or annulus pressure requirements) are consistent with those for other injection well types, while other requirements (e.g., use of automatic shut-off systems or tracers at the Director's discretion) are tailored to directly address the potential for large volumes of CO2 to be injected, among other factors.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24009 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language; 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment)
Comment: §146.81 Applicability.

Proposed Rule: (c) This subpart applies to owners and operators of permit or rule-authorized Class I industrial, Class II, or Class V experimental carbon dioxide injection projects who seek to apply for a Class VI geologic sequestration permit for their well or wells. If the Director determines that USDWs will not be endangered, such wells are exempt, at the Director’s discretion, from the casing and cementing requirements at §§146.86(b) and 146.87(a)(1) through (3).

Schlumberger Suggested Revision: (c) This subpart applies to owners andoperators of permit or rule-authorized Class I industrial, Class II, or Class V experimental carbon dioxide injection projects who seek to apply for a Class VI geologic sequestration permit for their well or wells. If the Director determines that USDWs will not be endangered, such wells are exempt, at the Director’s discretion, from the casing and cementing requirements at §§146.86(b) and 146.87(a)(1) through (3) if the wells were constructed prior to January 1,

2010.

Schlumberger Rationale: We feel that there needs to be a cutoff date for the grandfathering of wells so eventually all Class 6 wells are constructed to the

same standard

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 clarifies that only the construction requirements are grandfathered and that all other Class VI requirements (reporting, monitoring, mechanical integrity testing, etc.) must be met following a determination under §146.81(c).

EPA does not plan to institute a "cut-off date" for this requirement since conversion is a site-specific decision. EPA believes that the requirement should be based on the specific aspects of the well's construction, not on the date on which it was constructed.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24032 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: §146.86 Injection well construction requirements.

Proposed Rule: (1) Prevent the movement of fluids into or between USDWs or into any unauthorized zones;

Schlumberger Suggested Revision:(1) Prevent the movement of fluids into or between USDWs or into any unauthorized zones that causes endangerment;

Schlumberger Rationale: -

Response: EPA disagrees with the suggested edit. EPA believes that protection of USDWs from endangerment and prevention of fluid movement between formations is paramount, and believes that the language as proposed meets the standards in SDWA §1421. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of the requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 146.87.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24035Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule: (vi) Down-hole temperatures;

Schlumberger Suggested Revision: (vi) Down-hole temperatures and pressures;

Schlumberger Rationale: -

Response: EPA believes the requirement at 146.86(b)(1)(ii), which requires consideration of Injection pressure, external pressure, internal pressure, and axial loading addresses this concern, and therefore the proposed change is unnecessary.

Commenter Name: Pamela A. Lacey Letter ID: 0228 Commenter Organization: American Gas Association Comment ID: 21804 Other EPA Comment Codes and Descriptions: 4140 2.4.1.4 Use of fracturing for GS in specific geologic settings (seeking comment)
Comment: - Require Analysis before Hydraulic Fracturing for GS Wells Near Gas Storage: Before hydraulic fracturing of a GS injection well, the GS operator should perform an analysis to consider the proximity, both laterally and vertically, of the GS zone to existing natural gas storage reservoirs, and should analyze the fracturing design to examine the potential for communication with a natural gas storage reservoir. This could be added to the injection well construction requirements in section 146.86.

Response: EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director. Owners or operators must submit a proposed stimulation program as part of the permit application (§146.82(a)(9)); the plan must demonstrate that any stimulation activities will not compromise the integrity of the confining zone. The Director will evaluate the owner or operator's proposed stimulation plan in the context of all information about the site, and the owner or operator must perform stimulation only as approved.

The final rule also requires that the owner or operator notify the Director 30 days before performing stimulation during injection operations (§146.91(d)(2)); this will provide an additional opportunity for the Director to review the owner or operator's plans for stimulation and add other requirements as needed. EPA clarifies that UIC regulations prohibit fracturing of the confining zone at any time during injection or stimulation.

EPA believes that the extensive requirements for geologic site characterization (at §146.82), AoR evaluation (§146.84), and testing of the well during drilling (§146.87) are appropriate to ensure that permitting authorities have the necessary information to evaluate whether a specific site will allow safe injection of CO2. EPA believes that any natural gas storage operations will be identified during site characterization pursuant to requirements at §146.82 and §146.83 as will any faults or fractures.

Commenter Name: Pamela A. Lacey Letter ID: 0228 Commenter Organization: American Gas Association Comment ID: 21805 Other EPA Comment Codes and Descriptions: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)Comment: - Ensure Collaborative Process for GS Construction in Gas Storage Fields: Gas storage operators have particular expertise regarding their natural gas storage fields, and can help prevent problems if EPA helps to ensure their participation in the process of the site evaluation and construction of GS wells in natural gas storage fields. We ask you to revise sections 146.86 and 146.87 so as to authorize the Director to ensure the coordination between gas storage operators and GS well owners/operators in circumstances where the GS construction will occur in natural gas storage fields. Such coordination can involve, for example, obtaining input from the gas storage operators on the unique circumstances associated with the gas storage field where the GS well will be constructed. To assist in this process, gas storage field operators should have ready access to GS well records, well logs and cementing records for any GS construction activity that occurs in a gas storage field.

Response: EPA agrees that GS owners and operators and gas storage operators should coordinate when deciding where to locate their facilities. EPA expects that the permitting authority will be involved in this decision during the permit application process and when approving the permit. The permit application requires at §146.82(a)(2) that owners or operators submit a map showing all injection wells, which would include wells used for gas storage. The permitting process also requires at 124.10(c)(1)(xi) the notification of the state oil and gas agency and state mineral recovery agency, among others, when the draft permit is available for comment. The draft permit will also include the permit application. EPA believes that those agencies that should be involved in the decision will be properly informed under the final rule application and notification procedures.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24897 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86

EPA Proposal: 6. Injection well construction requirements

(a) General. The owner or operator must ensure that all Class VI wells are constructed and completed to:

(1) Prevent the movement of fluids into or between USDWs or into any unauthorized zones; (2) Permit the use of appropriate testing devices and workover tools; and (3) Permit continuous monitoring of the annulus space between the injection tubing and long string casing.

GWPC Recommendations: (a) General. The owner or operator must ensure that all Class VI wells are constructed and completed to:

(1) Prevent the movement of fluid containing any contaminant into USDWs per 40 CFR Part 144.12(a). (2) Permit the use of appropriate testing devices and workover tools; and (3) Permit continuous monitoring of the annulus space between the injection tubing and long string casing.Rationale: Mirror language concerning endangerment standard in (1).

The GWPC suggests re-wording (a)(1) to simplify and make it consistent with the
CFR definitions of fluid movement.

Response: EPA believes that protection of USDWs from endangerment and prevention of fluid movement between formations is paramount and believes that the language as proposed meets the non-endangerment standard provided in SDWA and §144.12. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of the requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 146.87.

Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment EPA has made many revisions to the GS rule. Please see the final rule and preamble for additional information.

Commenter Name: Mark Vickery Letter ID: 0280 Commenter Organization: Texas Commission on Environmental Quality Comment ID: 24101
Comment: (c) Concern exists that the proposed well design and construction requirements for Class VI wells will be unjustifiably burdensome. Experience in CO2 injection for enhanced oil and gas recovery indicates that the Class II well casing and cementing requirements are sufficient for protection of underground sources of drinking water. A more stringent alternative to the Class II requirements, but a definite improvement over the proposed Class VI requirements in this regard, could be made by adoption of the EPA-approved Class I well casing and cementing standards at Title 30, Texas Administrative Code, Section 331.62. This section of the Texas rules provides clearer and more enforceable standards, with greater emphasis on proactive planning to improve results in cementing of well casings.

Response: Although the requirements are based on the existing regulatory framework for deep wells, including Class I wells, EPA believes that GS is sufficiently different from other injection operations to warrant the tailored requirements for Class VI wells at §146.86.

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. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will 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. Therefore, Class VI GS reservoir pressures will increase more in comparison to Class II ER during the injection phase of the GS project.

Commenter Name: Olon Plunk Letter ID: 0536 Commenter Organization: Xcel Energy Comment ID: 21378 Other EPA Comment Codes and Descriptions: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83); 4000 2.4 Proposed Injection Well Operating Requirements (40 CFR 146.88); 5000 2.8 Proposed Well Plugging and Post-Injection Site Care Requirements
Comment: We believe there must be suitable CO2 injection plans backed by seismic surveys,multi dimensional modeling simulations and formation testing.

We recognize the overriding importance of well design and construction that assures well integrity. We believe there must be a sound operations management program including appropriate monitoring and corrective actions that are prepared and implemented by experts in the field.

We recognize both the local and national interest in providing effective post injection site care and closure and demonstrating adequate financial responsibility for these activities. While agreeing with supporting all of these important program elements, I would like to add a few words of caution.

Response: EPA acknowledges the comment. The GS requirements are designed to ensure protection of USDWs from endangerment by requiring that injection wells are permitted, sited, constructed, operated, monitored, and plugged in a manner that does not endanger USDWs. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of the requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 146.87.

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 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 evaluating this information. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 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 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 evaluating this information. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Comment Code: 3820 2.3.1 Well construction procedures



### Individual Comments

Commenter Name: Michael H. Cochran Letter ID:

0108 Commenter Organization: Bureau of Water, Division of Environment, Kansas Department of Health & Environment (KDHE) Comment

ID: 21974
Comment: 146.87 (b): Should include the stipulation for new wells only that new casing shall be used. This ensures the proper casing is used and is cheap insurance. Also gives a good baseline to start with.

Response: Although the rule does not specifically require the use of new casing, EPA expects thatonly new casing will be allowed in the construction of Class VI wells. The GS rule at §146.82(a)(7), requires owners or operators to submit information on planned injection pressures, which the Director will use in evaluating the proposed casing, tubing, and packer design. EPA adds that, in determining the suitability of well materials and the design of the well, the Director must consider various aspects of the injection project, including injection pressure, external pressure, internal pressure and axial loading in §146.86(b)(1)(ii), corrosiveness of the CO2 stream, and formation fluids in §146.86(b)(1)(v).

Commenter Name: Carl Carlsson Letter ID: 0131 Commenter Organization: SUEZ Energy Generation NA, LLC Comment ID: 21531
Comment: Specification of Well Construction Materials SEGNA agrees with EPA's position that the proposed rules should not specify materials that may be used, but rather should allow the owner or operator flexibility to choose, provided that the materials used are corrosion-resistant and meet appropriate standards. Well casing materials should be appropriate to the application, taking into account the chemical nature of the injected fluids and any additives, as well as the subsurface environment.

Response: EPA acknowledges the comment and agrees that, given the continuing evolution of material design and the numerous variables possible in a long-term GS project, listing specific requirements for casing and cement would not be appropriate. Rather, requiring that materials have sufficient structural strength and be compatible with fluids with which they may come in contact, in §146.86(b)(1), allows the owner or operator to determine the best casing and cementing design for each project based on information about the site and the planned injection and allows the Director to approve that design.

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.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141 Commenter Organization: Global Energy, Inc. Comment ID: 23091 Other EPA Comment Codes and Descriptions: 1420 1.2.1.1 Support the GS rulemaking
Comment: 2.Well installation, operation, monitoring, record keeping, and corrective action are similarly rigorous and reasonably pragmatic; and they materially minimize the potential for inappropriate actions.

Response: EPA acknowledges the comment and agrees that protection of USDWs from endangerment and prevention of fluid movement between formations is paramount. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of the requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 146.87.

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 GSincluding 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.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141 Commenter Organization: Global Energy, Inc. Comment ID: 23099 Other EPA Comment Codes and Descriptions: 5240 2.8.2.2 Post injection timeframe (seeking comment)
Comment: 1.Global strongly believes that excessive rigor in siting and well installation criteria, as well as post closure care and financial assurance for 50-years, would adversely impact acceptance of the program as well as the speed with which large (meaningful) scale carbon management develops.

We appreciate the challenge in balancing security of sequestration. However advocating proven and reliable applications based on use of oil & gas based technology should be adequate to ensure long-term safety and reliability.

Response: EPA disagrees that a post-injection site care timeframe of 50 years is excessive or that it overstates the risk of GS. 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 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 site-specific 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 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 believes however, that to ensure USDW protection from endangerment, a default timeframe for post-injection site care will be necessary in all but a limited number of cases. This default 50 year post-injection site care timeframe represents a reasonable and protective monitoring period based on a review of research studies, industry reports, and existing environmental programs, and evaluation of public comments.

To the comment about the cost of post-injection site care, EPA does not agree that post-injection sitecare timeframes longer than 30 years will be prohibitively expensive. In fact, EPA believes that postinjection site care monitoring will represent a relatively minor component of total project cost, and will provide an essential level of protection from endangerment for USDWs. A discussion of the costs attributed to monitoring technologies (used during injection and the post-injection site care timeframes) is available in the Technology and Cost Document for the GS rule, which is in the federal docket for this rulemaking. EPA believes that it is logical to make use of existing monitoring infrastructure at a GS site in order to ensure USDWs are not endangered.

EPA also recognizes the concerns associated with ensuring financial responsibility for the long time frames over which post-injection site care will be conducted. EPA is developing guidance on financial responsibility to assist owners or operators in evaluating the requirements of §146.85 and to assist Directors in evaluating financial responsibility demonstrations. The guidance describes the types of financial mechanisms that operators may choose to use when evaluating the financial responsibility requirements for GS wells and it will also include a section on how to estimate costs to support accurate financial responsibility demonstrations. The guidance will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced recovery and that many of the wells used for ER may be suitable for GS. However, 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. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will 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. Therefore, Class VI GS reservoir pressures will increase more in comparison to Class II ER during the injection phase of the GS project.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141 Commenter Organization: Global Energy, Inc. Comment ID: 23110
Comment: Well Installation

1.We support the basic and conservative installation criteria proposed. We

Response: EPA acknowledges the comment and believes that appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of the requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 146.87.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22554
Comment: Well Construction, Testing, and ClosureWells will be an integral part of a CO2 sequestration operation. Wells will be used to inject CO2 into the target sequestration formation and monitor the sequestration and other formations that could be affected by the injection. Because wells represent a potential conduit for CO2 or formation fluids to move out of formation and possibly to the surface great care must be taken to construct wells such that they will not leak, monitor them to ensure that they do not start leaking, and close them to ensure that they do not become a leakage risk later. Wells must demonstrate the ability to contain both injected and native fluids without allowing significant movement between formations or to the

surface.

Response: EPA agrees and believes that appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of the requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 146.87.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22555 Other EPA Comment Codes and Descriptions: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 CFR 146.90)
Comment: Construction

Regardless of the site specific component the new wells will need to be designed to meet the overarching goals for all projects. The goals for and injection well will be to inject CO2 and to keep fluid from moving along the wellbore between formations or to the surface. The goals for a monitoring well are to monitor the injection or other formations and also to keep fluids from moving along the wellbore. To accomplish these goals the design of the well needs toaddress site-specific, objective-specific (monitoring or injection), and fluidspecific considerations. All injection wells should be cased and cemented to

Response: EPA agrees that appropriate injection well construction will depend on site-specific factors. In determining whether to grant a Class VI permit, the Director will evaluate the appropriateness of the proposed injection well 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 §146.86(b)(1). In addition to the flexibility given to the owner and operator, Director's discretion is specifically provided in §146.86(b)(1) for casing and cementing and §146.86(c)(2 and 3) for tubing and packer location and
type.

EPA believes that monitoring using wells in the injection zone (i.e., that penetrate the confining zone) can be safely performed if the wells are constructed to prevent flow between the injection zone and USDWs or other layers above the confining zone. 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 has developed a brief technical paper on construction of monitoring wells that perforate the confining zone; this paper can be found in the rulemaking docket. EPA is developing guidance onwell 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.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22557 Other EPA Comment Codes and Descriptions: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 CFR 146.90)
Comment: The materials used for construction need to be compatible with the injected fluid and compatible with the formation fluids. Both injection and monitoring
wells should be constructed to the same material standard unless there is an objective-specific reason not to, because they may both be subjected to similar aggressive down-hole conditions. In order to insure that proper wellbore construction materials are always selected a standard should be adopted that specifies wellbore materials should resist the expected downhole conditions to a sufficient degree such that degradation will not lead to leakage. The thicknesses of the casing and tubing must be sufficient to handle the pressure associated with the injected CO2. Although materials are an important aspect in well construction centralization of the casing is also important for insuring the cement job is successful. It is very important that the casing is centralized over the entire cemented section. This will provide the best condition to achieve full radial coverage of the cement between the casing and

the formation.

Response: EPA agrees that well materials need to be compatible with injected fluids and formation fluids. The GS rule at §146.86(b)(1) requires that all injection well materials be compatible with fluids with which the materials may be expected to come into contact. Further, the rule, at §146.82(a)(7), requires owners or operators to submit information on planned injection pressures, that the Director will use in evaluating the proposed casing, tubing, and packer design. EPA adds that, in determining the suitability of well materials and the design of the well, the Director must consider various aspects of the injection project, including injection pressure, external pressure, internal pressure and axial loading in §146.86(b)(1)(ii), corrosiveness of the CO2 stream and formation fluids in §146.86(b)(1)(v).

EPA requires under §146.90 that owners or operators submit proposed testing and monitoring plans to the Director at the time of the permit application. The operator will need to demonstrate that the monitoring wells will be constructed and operated in a manner that will be sufficiently protective of USDWs from endangerment. Monitoring wells will differ from injection wells in their purpose, casing sizes, and depth, although their casing and cementing will likely be similar. Unlike injection wells, monitoring wells will not need to be built to withstand CO2 injection, but, nonetheless, will need to be built with materials and a design that ensure integrity of the well throughout its planned
life so that the well does not serve as a conduit for movement of the CO2 stream or formation fluids. As described above, EPA is developing guidance on testing and monitoring at GS sites, which will discuss monitoring well construction. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22600Comment: Proposed Rule: 146.86(a)(3)

Comment: NGWA supports this provision

Response: EPA acknowledges the comment and agrees that protection of USDWs from endangerment and prevention of fluid movement between formations is paramount. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of the requirements for construction of Class VI wells at §146.86.

Commenter Name: Steven Pirner Letter ID: 0153 Commenter Organization: South Dakota Department of Environment and

Natural Resources Comment ID:

22147
Comment: 146.86 Injection well construction requirements - (a) (2) well must be constructed such to allow appropriate testing devices and work-over tools - this is a good clause also, as our Class II regulations have allowed for a temporarily abandoned well that was worked over in such a way so it will be difficult to MIT it - may have to bring in an expensive R(adio)A(ctive)T(racer log) test rig - we couldn't prevent it under our Class II regulations

Response: EPA acknowledges the comment and agrees that protection of USDWs from endangerment and prevention of fluid movement between formations is paramount. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation of the requirements for construction of Class VI wells at §146.86.

Commenter Name: James Childress Letter ID: 0158 Commenter Organization: Gasification Technologies Council (GTC) Comment ID: 23781
Comment: EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing and construction with a packer set opposite a cemented interval. EPA Notice 78.

The requirements for construction of the proposed Class VI CO2 injection wells should be similar to the Class II wells used for EOR. This will expedite the transition of EOR projects to CCS projects. This requirement also unnecessarily stigmatizes CO2.

Response: EPA recognizes that many early GS projects will be in depleting or depleted oil and gas fields and that grandfathering of wells used for ER, where appropriate and protective, can facilitate
the transition from ER to GS.

However, EPA believes that injection for the primary purpose of long term storage is sufficiently different from Class II ER operations and warrants tailored requirements for Class VI wells at §146.86. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will also be different, with Class VI injection operations involving large volumes of CO2 and likely having higher pressures within their storage formations than Class II ER projects.The final Class VI regulations require that any owner or operator injecting CO2 for the primary purpose of long term storage obtain a Class VI permit with some special consideration for the fact that they are transitioning from a well not originally designed to meet Class VI requirements. The Director has the authority to determine at what point a Class VI permit is required for those projects that are transitioning from the primary purpose of EOR to long term storage of CO2. The final regulation provides a set of technical factors for the Director to evaluate in making this determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs when there is an increased risk to USDWs as compared to traditional Class II operations while allowing for site-specific flexibility.

The final GS rule, at §146.81(c), allows the construction of ER wells to be grandfathered, 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). Only the cemented-in-place construction requirements will be grandfathered under the final GS rule; following conversion, these wells will be permitted as Class VI wells and be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final GS rule.

EPA is developing guidance on transitioning from Class II to Class VI. The guidance will assist Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI transition. The guidance describes the methods available for the Director to determine the risk posed to USDWs from a GS/ER project, and how the Director may determine if a project should be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA disagrees that the construction requirements for Class VI wells will stigmatize CO2 GS. Although the requirements are based on the existing regulatory framework for deep wells, including Class I wells, EPA believes that GS is sufficiently different from other injection operations to warrant the tailored requirements for Class VI wells at §146.86.

Commenter Name: Robert J. Finley Letter ID: 0180 Commenter Organization: Illinois State Geological Survey Comment ID: 23630
Comment: (c)(2)(vi)

This section (c) is headed tubing and packer and (2) requests information on requirements for such, but (vi) only requests size of casing and leaves out size of tubing while (vii) ask for specifications on the tubing but likewise ignores

basic size information.

Response: EPA has revised §146.86(c)(3)(vi) to require the owner or operator to submit information on the size of both tubing and casing.. The Director will determine whether tubing size, as proposed by the owner or operator, is appropriate based on the size of the casing. 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24337Comment: C. Injection Well Construction Requirements

1. Well Design

Many years of experience with the Class II UIC program - including 35 years of CO2 injection in the EOR context - have demonstrated that the construction requirements for Class II injection wells are sufficient to ensure that injected fluids cannot escape from the intended injection zone via the injection well borehole. The proposed rule would nevertheless impose substantially more costly well construction requirements resembling those for Class I hazardous waste injection wells. The Proposed Rule specifically cites the buoyancy of CO2 as the justification for these requirements. See 73 Fed. Reg. at 43509.

The buoyancy of CO2 in no way justifies the additional construction requirements proposed. The reason for this is straight-forward: by far the greatest driving force for fluid migration along an injection well borehole is the pressure build-up (or "cone of influence") caused by fluid injection during the operation of the injection well. The magnitude of this pressure influence is at its maximum at the point of injection, and - within the injection interval - it generally falls off logarithmically with lateral distance from the injection well borehole. At some distance from the injection well, the pressure influenceof the injection activity can be expected to decline to the point where densitydriven flow (i.e., buoyancy) could become significant (at least in relative terms) as a driver for vertical fluid migration. At the injection well, however, the induced pressure gradient caused by the injection activity would so dwarf the impact of buoyancy as to render the latter insignificant. Accordingly, it would be unreasonable to suggest that buoyancy justifies significantly more demanding injection well construction requirements than have already proven to be sufficient in the case of Class II CO2 injection wells.

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

EPA should rely primarily on the basic performance standards for well construction stated in proposed 40 C.F.R. 146.86(a) rather than on less flexible well design specifications. This approach has proved effective in the context of the Class II program, and leaves permit-writers free to tailor well construction requirements to the particular circumstances involved.

Response: EPA disagrees that buoyancy is not a consideration that needs to be addressed in the GS regulations. Field and laboratory studies that evaluated two deep wells exposed to CO2 for nearly three decades have provided evidence of upward vertical flow of CO2. In Carey et al (2007), a sample of well cement collected from a section of well in the confining zone at SACROC showed evidence of cement alteration (carbonation) due to exposure from CO2. (The study was not able to determine whether the alteration was due to exposure to CO2 in the presence of water, dry CO2, or to a CO2-brine mixture.) In Crow et al (2009), a similar study was conducted on a CO2 production well that was drilled into and completed in a natural CO2 producing formation. This study concluded that CO2 had caused alteration (carbonation) of the well cement and acidification of fluids adjacent to the caprock. The study could not determine if the alteration was due to exposure from CO2 diffusion up into the overlying caprock or by upward CO2 migration through wellbore system defects (perhaps cement-caprock and/or cement-formation interfaces). In both studies, the CO2apparently moved from the underlying reservoir into the well bore section located within the overlying caprock. These observations, especially in conjunction with the larger CO2 volumes and higher reservoir pressures anticipated with GS, justify the well construction requirements in the final GS rule in order to prevent deterioration of the materials between the well casing and the well bore that can result in unacceptable fluid movement.

EPA adds that buoyancy of CO2 is one of several considerations for large scale GS that warrant the tailored construction requirements at §146.86. For example, seismic surveys at Sleipner showed that CO2 had migrated to the top of the 200 to 300 meter thick formation as early as three years after injection began. The overall behavior of CO2 at Sleipner is for it to migrate to the top of the formation and spread laterally from there (Chadwick et al 2006). Additionally, CO2 has the potential to be corrosive (in the presence of water or aqueous formation fluids during CO2 injection), and the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II ER/ CO2 injection wells.

EPA believes that injection for the primary purpose of long-term storage is sufficiently different from Class II ER operations and warrants tailored requirements for Class VI wells at §146.86. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will also be different, with Class VI injection operations involving large volumes of CO2 and likely having higher pressures within their storage formations than Class II ER projects.

Commenter Name: John R. Baza Letter ID: 0193 Commenter Organization: Utah Division of Oil, Gas, and Mining Comment ID: 23913 Other EPA Comment Codes and Descriptions: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)
Comment: Proposed Well Construction Requirements

EPA proposed that construction of GS wells be tailored to the construction requirements of a Class IH well. The Division agrees that USDWs need to be protected; however, these construction requirements may be too stringent for existing Class II EOR wells. To require remedial work on existing wells to achieve the proposed standards may in fact compromise the established mechanical integrity of an existing Class II well. Additionally, the requirement to set surface casing and cement through the base of the lowermost aquifer would be too restrictive. The regulating agency should have the discretion to evaluate wells on a site-specific basis to insure that USDWs will be protected.

Response: EPA disagrees that the well construction standards for Class VI wells are too stringent. Rather, the construction requirements at §146.86 provide an appropriate level of protection from endangerment to USDWs that is based upon the existing UIC framework for deep wells. The new tailored approach was designed to address the general risks deep injection may pose to USDWs and was tailored specifically to address the unique nature of CO2 GS (i.e., 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 adds that promoting GS or carbon management efforts is outside the scope of the GS rulemaking, which focuses on protecting USDWs from endangerment.

Regarding the comment that remedial work will compromise the mechanical integrity of an existingClass II well, EPA clarifies that if a Class II well cannot be converted for GS injection and operated in a way that protects USDWs, including maintaining mechanical integrity and safe operation, conversion to Class VI will not be allowed. EPA believes that many Class II wells are constructed in a manner that would allow conversion for use as Class VI wells, but acknowledges that this may not
be the case for all such wells.

The final GS rule, at §146.81(c), allows the construction of ER wells to be grandfathered, 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). Only the cemented-in-place construction requirements will be grandfathered under the final GS rule; following conversion, these wells will be permitted as Class VI wells and be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final GS rule.

EPA is developing guidance on transitioning from Class II to Class VI. The guidance will assist Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI transition. The guidance describes the methods available for the Director to determine the risk posed to USDWs from a GS/ER project, and how the Director may determine if a project should be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Andy Horn Letter ID: 0196 Commenter Organization: Colorado Ground Water Association (CGWA) Comment ID: 23930
Comment: Issue 10. Well construction and well conversion issues are not adequately addressed in the proposed regulation. The conversion of wells from enhanced oil recovery (EOR) or hazardous waste injection to CO2 injection is vague.

Well construction and potential well conversion issues need to be addressed in the regulations. All materials with the potential to come into contact with the injectate and/or the formation fluids should be designed and tested to insure the materials’ integrity will be maintained and they will prevent movement of the injectate into a potential USDW zone. Materials that will not come into contact with the injectate and/or formation fluids in the zone of injection are not as critical, but sufficient design review should be performed to insure that proper materials are used for all well construction. All wells used for injection and monitoring should be operated according to a periodic maintenance schedule similar to other wells in the UIC program.

Response: EPA agrees that well materials need to be compatible with injected fluids and formation fluids. The GS rule at §146.86(b)(1) requires that all injection well materials be compatible with fluids with which the materials may be expected to come into contact. Further, the rule, at §146.82(a)(7), requires owners or operators to submit information on planned injection pressures, that the Director will use in evaluating the proposed casing, tubing, and packer design. EPA adds that, in determining the suitability of well materials and the design of the well, the Director must consider various aspects of the injection project, including injection pressure, external pressure, internal pressure and axial loading in §146.86(b)(1)(ii), corrosiveness of the CO2 stream, and formation fluids in §146.86(b)(1)(v).

Owners or operators seeking to convert existing wells for GS must demonstrate to the Director'ssatisfaction that the converted well can conduct GS operations in a manner that does not endanger USDWs. The final GS rule, at §146.81(c), allows the construction of these wells to be grandfathered, 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 is developing guidance on transitioning from Class II to Class VI. The guidance will assist Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI transition. The guidance describes the methods available for the Director to determine the risk posed to USDWs from a GS/ER project, and how the Director may determine if a project should be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Regarding operation of monitoring wells, EPA requires under §146.90 that owners or operators submit proposed testing and monitoring plans to the Director at the time of the permit application. The operator will need to demonstrate that the monitoring wells will be constructed and operated in a manner that will be sufficiently protective of USDWs from endangerment.

Commenter Name: Richard Guinn Letter ID: 0210 Commenter Organization: Eastman Chemical Company Comment ID: 22731
Comment: EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval. EPA Notice 78.

The requirements for construction of the proposed Class VI CO2 injection wells should be similar to the Class II wells used for EOR. This will expedite the transition of EOR projects to CCS projects. This requirement also unnecessarily stigmatizes CO2.

Response: EPA recognizes that many early GS projects will be in depleting or depleted oil and gas fields and that grandfathering of wells used for ER, where appropriate and protective, can facilitate
the transition from ER to GS.

However, EPA believes that injection for the primary purpose of long term storage is sufficiently different from Class II ER operations and warrants tailored requirements for Class VI wells at §146.86. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will also be different, with Class VI injection operations involving large volumes of CO2 and likely having higher pressures within their storage formations than Class II ER projects.

The final Class VI regulations require that any owner or operator injecting CO2 for the primary purpose of long term storage obtain a Class VI permit with some special consideration for the fact that they are transitioning from a well not originally designed to meet Class VI requirements. The Director has the authority to determine at what point a Class VI permit is required for those projects that are transitioning from the primary purpose of EOR to long term storage of CO2. The final regulation provides a set of technical factors for the Director to evaluate in making this determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs when there is an increased risk to USDWs as compared to traditional Class II operations while allowing for site-specific flexibility.The final GS rule, at §146.81(c), allows the construction of ER wells to be grandfathered, 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). Only the cemented-in-place construction requirements would be grandfathered under the final GS rule; following conversion, these wells must be permitted as Class VI wells and be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final GS rule.

EPA is developing guidance on transitioning from Class II to Class VI. The guidance will assist Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI transition. The guidance describes the methods available for the Director to determine the risk posed to USDWs from a GS/ER project, and how the Director may determine if a project should be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA disagrees that the construction requirements for Class VI wells will stigmatize CO2. Although the requirements are based on the existing regulatory framework for deep wells, including Class I wells, EPA believes that GS is sufficiently different from other injection operations to warrant the tailored requirements Class VI Class VI wells at §146.86.

Commenter Name: John King Letter ID: 0211 Commenter Organization: Shell Exploration and Production Company (SEPCo) Comment ID:

22749 Other EPA Comment Codes and Descriptions: 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.

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.

Commenter Name: John King Letter ID: 0211Commenter Organization: Shell Exploration and Production Company (SEPCo) Comment ID:

22769
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.

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.

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 tothe 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 cement-formation interfaces). In both studies, the CO2 apparently moved from the underlying reservoir into the well bore section located within the overlying caprock. These observations, especially in conjunction with the larger CO2 volumes and higher reservoir pressures anticipated with GS, justify the well construction requirements in the final GS rule in order to prevent deterioration of the materials between the well casing and the well bore that can result in unacceptable fluid movement.

EPA adds that buoyancy of CO2 is one of several considerations for large scale GS that warrant the tailored construction requirements at §146.86. For example, seismic surveys at Sleipner showed that CO2 had migrated to the top of the 200 to 300 meter thick formation as early as 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.

Commenter Name: Diane VanDe Hei Letter ID: 0213 Commenter Organization: Association of Metropolitan Water Agencies (AMWA) Comment ID:

22931
Comment: Aspects of permitting process:

- Well construction o EPA’s proposal requires that materials that meet or exceed industry standards must be compatible with injected CO2 and "are designed for the life of the well". As the CO2 may be stored underground indefinitely, are concretes and other well materials designed to last forever under the chemical and geological conditions expected in a carbon sequestration well? AMWA requests that EPA and DOE perform additional

research and data collection in this area.

Response: EPA clarifies that the rule requires that all well materials be compatible with fluids with which they may come in contact and be of sufficient structural strength to last 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 (73 FR 43510). 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 the movement of fluids associated with future injection operations.

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23967 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rulelanguage; 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment)
Comment: 1. § 146.81 Applicability

The proposed rule provides that owners or operators of authorized Class I industrial, Class II, or Class V experimental CO2 injection projects who seek to "convert" these wells to Class VI wells and apply for a Class VI permit may be exempted, at the Director’s discretion, from the proposed casing and cementing requirements applicable to Class VI wells.

EPA Proposed § 146.81(c) This subpart applies to owners and operators of permit or rule- authorized Class I industrial, Class II, or Class V experimental carbon dioxide injection projects who seek to apply for a Class VI geologic sequestration permit for their well or wells. If the Director determines that USDWs will not be endangered, such wells are exempt, at the Director’s discretion, from the casing and cementing requirements at §§ 146.86(b) and 146.87(a)(1) through (3).

It is helpful that EPA recognizes that entities may wish to convert other classes of wells (such as Class II wells used for CO2 enhanced oil recovery projects) into Class VI wells and that flexibility is necessary for this conversion process. This flexibility should be maintained in the final rules but should be enhanced. In addition, the rules should be expanded to provide further detail on the conversion process. It is critical that owners and operators have clear and concise rules to rely on when seeking to grandfather their existing wells. This provision should be revised to limit the Director’s discretion and address all variances resulting in modifications to existing wells. For instance, while the rules waive the Class VI casing and cementing requirements for existing wells being converted to Class VI wells, the rules do not address other construction or construction-related Class VI well requirements that create variances between Class VI and Class I, II and V wells. Those requirements include:

1. Down hole automatic shut-off valve with wellhead hydraulics; 2. Annulus liquid level detector; 3. Wellhead corrosion monitoring equipment; and 4. Mechanical integrity testing.

Each of these requirements applicable to Class VI wells would require retrofitting or modifications to existing wells and could make conversion of wells impracticable or excessively expensive. Rather than requiring existing wells to meet prescriptive rules that may not be necessary or applicable, the decision to grandfather an existing well should be based solely on the well’s passing a mechanical integrity test without physical well modification and meeting all other Class VI permit requirements that may be met without well modification. This change could be accomplished by revising proposed § 146.81(c)
as follows:

(c) This subpart applies to owners and operators of permit or rule-authorized Class I industrial, Class II, or Class V experimental carbon dioxide injection projects who seek to apply for a Class VI geologic sequestration permit fortheir well or wells. If the Director determines that USDWs will not be endangeredTHROUGH THE RESULTS OF MECHANICAL INTEGRITY TESTING PURSUANT TO § 146.89 THAT THE WELL IS EFFECTIVE IN PREVENTING ENDANGERMENT OF USDWS,
such wells are exempt, at the Director’s discretion , from the casing and cementing requirements at §§ 146.86(b) and 146.87(a)(1) through (3) ANY REQUIREMENT IMPOSING PHYSICAL WELL MODIFICATIONS, SUBJECT TO MEETING

ALL OTHER CLASS VI WELL REQUIREMENTS.

Response: EPA expects that any decision to convert a well for long term storage of CO2 be made in the context of all available information about the site and history of injection. 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 clarifies that other Class VI requirements (i.e., beyond the construction requirements) will not be grandfathered. Following conversion of the project to Class VI, many of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water) warrant the specific operational, MIT, monitoring, reporting, plugging, post-injection site care, and site closure requirements in the final GS rule. Therefore, following re-permitting, these projects must be subject to the requirements in the final GS rule, including requirements related to down-hole shut-off devices, annulus fluid monitoring, corrosion monitoring, and MITs. EPA adds that only requiring a MIT test for wells converting from Class I, II, or V would not be sufficient to ensure that the well was adequate to properly contain the buoyant and corrosive nature of the CO2 stream. EPA believes that down-hole shut-off systems and corrosion monitoring are also necessary to ensure the well maintains its integrity. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on these requirements.

If, because of its construction, a current Class II well cannot be converted for GS in such a way that USDWs are protected from endangerment (i.e., by meeting the monitoring, MIT, and other requirements for Class VI wells), conversion will not be allowed. While conversion of suitable Class II wells for GS is desirable in many situations, EPA stresses that protection of USDWs from endangerment is the primary mission and mandate of the UIC program.

To clarify the point at which the primary purpose of CO2 injection transitions from ER (i.e., a ClassII well) to long-term storage (i.e., Class VI), the final GS rule at §144.19 contains specific, riskbased factors to be considered by the Director in making this determination. Furthermore, EPA is developing guidance on transitioning from Class II to Class VI. The guidance will assist Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI transition. The guidance describes the methods available for the Director to determine the risk posed to USDWs from a GS/ER project, and how the Director may determine if a project should be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Tiffany Rau Letter ID: 0224Commenter Organization: Hydrogen Energy International Comment ID: 21682
Comment: Furthermore, section 146.86(b)(5) should be amended to base the choice of casing and cement materials on the planned operating life of the well as opposed to the ultimate duration of the geologic sequestration project. EPA may have set the duration as the life of the project in an effort to prevent corrosion of the casing over the long term after injection has ceased. However, this legitimate concern is mitigated by appropriate plugging of the static well at the end of its life. This plugging could employ corrosion-resistant material, if an extra level of mitigation were deemed necessary at that time based upon site characteristics. API has submitted specific language to address the foregoing. We support API’s proposed language modification to section 144.86 (b)(5).

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 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 USDW 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.

Commenter Name: Brian Williams Letter ID: 0225 Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21732
Comment: Furthermore, section 146.86(b)(5) should be amended to base the choice of casing and cement materials on the planned operating life of the well as opposed to the ultimate duration of the geologic sequestration project. EPA may have set the duration as the life of the project in an effort to prevent corrosion of the casing over the long term after injection has ceased. However, this legitimate concern is mitigated by appropriate plugging of the static well at the end of its life. This plugging could employ corrosion-resistant material, if an extra level of mitigation were deemed necessary at that time based upon site characteristics. API has submitted specific language to address the foregoing. We support API’s proposed language modification to section 144.86 (b)(5).

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 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 USDW 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.Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24034 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule: (ii) Injection pressure, external pressure, internal pressure and axial loading;

Schlumberger Suggested Revision: (ii) Injection pressure, external pressure, internal pressure and axial loading;

Schlumberger Rationale: What is meant by external and internal pressure?

Response: The internal and external pressure mentioned in §146.86(b)(1)(ii) refers to pressure on the well casing. Internal pressures could be caused by cement or annular fluids; external pressures could be caused by cementing against the borehole or pressure head from formations. 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.

Commenter Name: Steven B. Corneli Letter ID: 0234 Commenter Organization: NRG Energy, Inc. Comment ID: 23165
Comment: Proposed Class VI Well Standards

The proposed Class VI well construction requirements are as stringent as those for hazardous waste injection (Class I). NRG believes that this is not a logical or appropriate regulatory approach to ensure protection of USDWs. The injection of CO2 does not warrant the same level of regulations as hazardous waste injection.

The primary issues associated with CO2 injection for GS are related to the enormous volumes and the mobility of CO2 in the subsurface. However, the Class VI requirements do not address these issues. These stringent well construction requirements will only increase the costs of operation resulting in no additional protection of USDWs. NRG agrees with the Carbon Sequestration Council’s recommendation to use the Class II regulations as a starting point for the development of the Class VI regulations. The oil and gas industry has several decades of CO2 injection experience with the Class II UIC program and has demonstrated that the construction requirements for Class II injections wells are sufficient to protect human health and the environment.

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced recovery and that many of the wells used for ER may be suitable for GS. However, EPA believes that GS is sufficiently different from Class II ER operations to warrant the tailored requirements for Class VI wells. EPA believes that the construction requirements for Class VI wells, along with other requirements, e.g., site characterization, are tailored to address the unique issues associated with large-scale GS and are necessary to protect USDWs from endangerment and that lesser standards could potentially endanger USDWs. EPA believes that the construction requirements most directly address corrosivity concerns, while the large volumes and the mobility ofCO2 in the subsurface are addressed by the siting requirements at §146.83.

For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells, and reservoir pressure conditions will 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. Therefore, Class VI GS reservoir pressures will increase more in comparison to Class II ER during the injection phase of the GS project.

EPA acknowledges that the Class VI requirements have associated costs beyond baseline costs assumed in the cost analysis for this rule (based on an assumption that Class I industrial wells are the baseline). EPA believes that the requirements for Class VI wells provide multiple layers of USDW protection from endangerment that justify the cost of meeting the requirements. The Agency clarifies that the purpose of the GS regulation, promulgated under authority of the SDWA, is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.

Commenter Name: Robert E. Carter Jr. Letter ID: 0236 Commenter Organization: Indiana Department of Natural Resources (IDNR) Comment ID: 29216
Comment: States like Indiana with a proven track record of effectively managing similar programs have indeed demonstrated an ability to adapt to evolving technologies and we believe do possess the capability to effectively address long-termstorage issues. In fact, as indicated earlier in our comments, many of the longterm issues associated with CCGS operations will be outside the purview of the UIC Program and will need to be addressed by states as they enact appropriate CCGS legislation. EPA should consider implementing rules which afford states with the greatest flexibility to select regulatory options that are best suited to their specific needs and conditions. Specific examples of requirements that may be too prescriptive include:

1. Well casing and cementing standards.

Response: EPA disagrees that the well construction standards for Class VI wells are too stringent. Instead, the construction requirements at §146.86 provide an appropriate level of protection from endangerment to USDWs that is based upon the existing UIC framework for deep wells. The new tailored approach was designed to address the general risks deep injection may pose to USDWs and was tailored specifically to address the unique nature of CO2 GS (i.e., 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 also believes that the regulations allow appropriate flexibility to the Director to evaluate theappropriateness of the owner or operator's proposed well construction procedures based on sitespecific information about the injection project, including injection pressures, injection and confining zone lithology, and information about the carbon dioxide stream as provided in §146.86(b)(1). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA believes that, given the continuing evolution of material design and the numerous variables possible in a long-term GS project, listing specific requirements for casing and cement would not beappropriate. Rather, requiring that materials have sufficient structural strength and be compatible with fluids with which they may come in contact, in §146.86(b)(1), allows the owner or operator to determine the best casing and cementing design for each project based on information about the site and the planned injection and allows the Director to approve that design.

Commenter Name: Mark E. Fesmire Letter ID: 0237 Commenter Organization: New Mexico Oil Conservation Division (NMOCD) Comment ID: 23212

Comment: B. Section 146.86 "injection well construction" - sub section (B)(2) requires a sufficient number of centralizers, but does not establish the objective of the centralizer placement. It is suggested that this section require a "sufficient number of centralizers to insure an adequate cement bond to prevent fluid communication under injection pressures."

Response: EPA clarifies that centralizers serve to keep the casing centered in the wellbore during drilling and cementing. If the casing is not centered, it can be difficult to remove the drilling mud and the cement job may not be even. This can lead to an inadequate cement job.

Commenter Name: Philip Papadeas Letter ID: 0238 Commenter Organization: Sandia Technologies, LLC Comment ID: 23345
Comment: For long term disposal, or storage, well tubular requirements should be robust and manage potential impurities in the injection stream, with no limitations so long as proper injection pressures and well materials are sufficiently followed during operations.

Response: EPA agrees that tubular materials in Class VI wells must be suitable for handling the CO2 stream. The final GS rule at §146.86(c)(1), requires that tubing materials used in Class VI wells meet or exceed standards developed by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. This requirement invokes the expertise of these bodies without the added burden of a certification program. The GS rule, at §146.86(c)(3)(ii), also requires the Director to consider the characteristics of the CO2 stream (i.e., chemical content, corrosiveness, temperature, and density) and formation fluids in approving the construction of a
Class VI well.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23289
Comment: 146.86(b)5 Request clarification whether a CBL with VDL image is sufficient.

Response: A cement bond log with a variable density log image is one of the methods that could be used to evaluate cement quality radially. Radial evaluation of cement is generally done using acoustic instruments which emit signals through a transmitter and then receive the response in receivers. The speed at which the wave returns and the amount of attenuation provide information about the material through which the waves travel. The logging and testing requirements at §146.87(a) describe the complete suite of tests to be used before and upon installation of the surface casing and long-string casing.

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 VIwells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Letter ID: 0263 Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22802 Other EPA Comment Codes and Descriptions: 1250 1.1.1.4 Flexibility is needed (performancebased standards)
Comment: III A. 3 Proposed Injection Well Construction Requirements

Q. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval.

IOGCC Response: IOGCC agrees with the need for adequate protection of USDWs and theproposed measures. However, Director discretion is necessary to address sitespecific conditions. Well construction should be evaluated so as to insure necessary protections of the USDWs, and should not be overly prescriptive.

Response: EPA agrees that, given the continuing evolution of material design and the numerous variables possible in a long-term GS project, listing specific requirements for casing and cement would not be appropriate. Rather, requiring that materials must have sufficient structural strength and be compatible with fluids with which they may come in contact, in §146.86(b)(1), allows the owner or operator to determine the best casing and cementing design for each project based on information about the site and the planned injection and for the Director to approve that design.

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.

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



### Individual Comments

Commenter Name: Michael H. Cochran Letter ID:

0108 Commenter Organization: Bureau of Water, Division of Environment, Kansas Department of Health & Environment (KDHE) Comment

ID: 21972
Comment: 146.86(b)(2): Some flexibility should be considered on the amount if surface casing required because of the many protective testing and monitoring requirements and the multilayer protection system provided by the requirement of tubing and packer and the longstring being cemented bottom to surface. Setting the surface casing through the USDW in some areas may not be practical due to the considerable depth. As an alternative, we recommend that surface casing be set through the deepest water bearing zone that is currently used for a water supply.Response: EPA believes that the regulations allow appropriate flexibility regarding the surface casing. The GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of single or multiple strings of casing and cement. It does not, however, specify how cementing would be accomplished, and gives flexibility to the owner or operator to propose alternate methods that provide an amount of cement sufficient to meet the standard that USDWs are protected. 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 disagrees that other requirements for Class VI wells, such as tubing and packer or monitoring requirements, negate the need for proper surface casing. Each of these measures provides a different but necessary level of USDW protection. EPA believes that all of the requirements for Class VI wells, working together, provide multiple barriers of protection against endangerment of USDWs.

Commenter Name: Leslie Savage Letter ID: 0122 Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24784 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: (2) Surface casing must extend through the base of the lowermost USDW ABOVE THE
INJECTION ZONE and be cemented to the surface.

Response: EPA disagrees with the suggested edit. The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single string or multiple strings of casing and cement.

EPA stresses that protection of USDWs from endangerment, regardless of their depth or the number of USDWs in an area, is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, the activity will not be allowed under UIC requirements or the SDWA.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of Class VI wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. EPA believes that, given the possibility for Class VI wells to operate under injection depth waivers, the requirement that surface casing must extend through the base of the lowermost USDW is important for USDW protection.

Commenter Name: John Stormon Letter ID: 0123 Commenter Organization: Washington State Dept. of Ecology Comment ID: 23003
Comment: Well Standards: The well construction standards may be difficult or impossible to meet in some geologic settings. The standards require a surface casing installed to the lowermost USDW and cemented to the surface. In geologic settings with bedrock and deep drinking water quality aquifers, it may be impossible to set the surface casings this deep. Washington's Columbia Riverbasalts may be as deep as 10,000 ft, much of that depth with drinking water quality ground water. The multiple flows and fractures in these beds make for difficult drilling and frequently require setting intermediate casings. The standards should allow a protective casing program that can be reliably installed in all geologic settings. Deep aquifers may provide the most protective geologic settings for CO2 injection; the standards should not discourage their use.

Response: EPA disagrees that the surface casing requirements in the GS rule preclude injection below deep USDWs. The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of single or multiple strings of casing and cement. It does not, however, specify how cementing must 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. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of Class VI wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141 Commenter Organization: Global Energy, Inc. Comment ID: 23111 Other EPA Comment Codes and Descriptions: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)
Comment: 1.We support the basic and conservative installation criteria proposed. We question whether casing to the injection horizon, cementing the full length is really necessary. It seems certain that experts in geology and well installation should have the latitude to determine the appropriate installation method. Appropriate instrumentation and shut-offs are reasonable.

Response: EPA believes that the requirements for surface and long-string casing are necessary and also that they offer appropriate flexibility. The final GS rule requires, at §146.86(b)(2), that the surface casing must extend through the base of the lowermost USDW and be cemented to the surface, and that at least one long string casing must be cemented to the surface in one or more stages at §146.86(b)(3). 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).

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22556 Other EPA Comment Codes and Descriptions: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)
Comment: specific considerations. All injection wells should be cased and cemented to stop fluid movement between formations. A surface casing should be installed and set below the lowermost USDW above the injection zone and cemented along its entire length. It is important when considering the height of the cement sheath behind the long-string casing to consider the overall "design" of the injection and monitoring zones. Because, it is ideal to have a secondary caprock it will be imperative to cement the well, at a minimum, from the injection zone to a level above the secondary confining unit. If the borehole through the secondary caprock is left uncemented the effectiveness of the secondary caprock will be greatly reduced. Furthermore, it may be advisable to cement the casing along the entire length to protect the casing from degradation due to anodic dissolution [Anstice et al., 2005] or exposure to corrosive formation fluids. If the casing is not cemented along its entire length it may be necessary to use cathodic protection, depending on the site, to keep the casing from degrading. Watson and Bachu, [2007] found that about 81% of wells in their study area that had surface casing vent flows (leaks) had them above the top cemented section.

Anstice, D.J., Page, C.L., and Page, M.M., 2005, "The pore solution phase of carbonated cement pastes," Cement and Concrete Research, Vol. 35, pp. 377-383.

Watson, T.L. and Bachu, S., "Evaluation of the potential for gas and CO2 leakage along wellbores," paper SPE 106817 presented at the 2007 E&P Environmental and Safety Conference, Galveston, TX, March 5-7, 2007.

Response: EPA agrees that the casing should be cemented along its entire length. The final GS rule requires, at §146.86(b)(2), that the surface casing must extend through the base of the lowermost USDW and be cemented to the surface, and that at least one long string casing must be cemented to the surface in one or more stages at §146.86(b)(3). EPA believes that these requirements are an important component of construction that will protect USDWs from endangerment.

Cathodic protection can also be used to control corrosion, even when the long-string casing is fully cemented. Though not required for all wells, additional techniques like cathodic protection may be required by the Director if he/she determines they are necessary at a specific location to ensure protection of USDWs. EPA adds that the Director also has the authority to require a casing inspection log, as specified at §146.89(d), which can be used to determine the presence or absence of corrosion of the long-string casing and can give early warning of casing problems with corrosion.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.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22602 Other EPA Comment Codes and Descriptions: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)
Comment: Proposed Rule: 146.86(b)(3)

Comment: NGWA supports this provision

Response: EPA disagrees that protecting deep USDWs underlying multiple, more shallow USDWs is "overkill." Protection of USDWs, regardless of their depth or stratigraphic location, is the primary mission and mandate of the UIC program—as specified by Congress in the SDWA—and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such a demonstration cannot be made, then the activity will not be allowed under UIC requirements or the SDWA. Water agencies commenting on the proposed rule noted that diminishing water supplies are requiring water utilities to use deeper and more saline sources, and the SDWA mandates EPA to set regulations that protect USDWs from endangerment.

The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single string or multiple strings of casing and cement. It does not, however, specify how cementing must be accomplished, and it allows the owner or operator to propose alternate methods that provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Steven Pirner Letter ID: 0153 Commenter Organization: South Dakota Department of Environment and

Natural Resources Comment ID:

22148
Comment: (b) (2) extending surface casing through the base of the lower-most USDW - this may be over kill in areas where there are multiple aquifers at numerous different depths. Especially in areas where the upper USDWs easily fulfill the needs of the populace, and the deeper USDWs are of high TDS content, and may take considerable, expensive treatment to bring it to palatable levels. In addition, this would be more overkill if both the tubing and long stringinjection casings are cemented from bottom to surface.

Response: EPA disagrees that protecting deep USDWs underlying multiple, more shallow USDWs is "overkill." Protection of USDWs, regardless of their depth or stratigraphic location, is the primary mission and mandate of the UIC program—as specified by Congress in the SDWA—and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such a demonstration cannot be made, then the activity will not be allowed under UIC requirements or the SDWA. Water agencies commenting on the proposed rule noted that diminishing water supplies are requiring water utilities to use deeper and more saline sources, and the SDWA mandates EPA to set regulations that protect USDWs from endangerment.

The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single string or multiple strings of casing and cement. It does not, however, specify how cementing must be accomplished, and it allows the owner or operator to propose alternate methods that provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: James Childress Letter ID: 0158 Commenter Organization: Gasification Technologies Council (GTC) Comment ID: 23773 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: §146.86 Injection well construction requirements. (b) (2) "Surface casing must extend through the base of the lowermost USDW and be cemented to the surface. "

We recommend striking out this requirement in its entirety. This will be prohibitively expensive in deep wells, and may not be necessary at all sites.

Response: EPA disagrees that protecting deep USDWs underlying multiple, more shallow USDWs is unnecessary. Protection of USDWs, regardless of their depth or stratigraphic location, is the primary mission and mandate of the UIC program—as specified by Congress in the SDWA—and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such a demonstration cannot be made, then the activity will not be allowed under UIC requirements or the SDWA. Water agencies commenting on the proposed rule noted that diminishing water supplies are requiring water utilities to use deeper and more saline sources, and the SDWA mandates EPA to set regulations that protect USDWs from endangerment.

The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single string or multiplestrings of casing and cement. It does not, however, specify how cementing must be accomplished, and it allows the owner or operator to propose alternate methods that provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24174 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(2)

API Comments: (2) Surface casing must extend through the base of the lowermost
USDW ABOVE THE INJECTION ZONE and be cemented to the surface.

Rationale: In some parts of the US the USDW is very deep and this standard may preclude geologic sequestration in these areas.

Response: EPA disagrees with the suggested edit or that the surface casing requirements in the GS rule preclude injection below deep USDWs. The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of single or multiple strings of casing and cement. It does not, however, specify how cementingmust be accomplished, and gives flexibility to the owner or operator to propose alternate methodsto provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24229
Comment: Rule Provisions: 146.86(b) EPA Preamble Question: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval. EPA Notice43509.

API Response: Generally the surface casing is set below the lower USDW but it should be recognized that this is not appropriate in all geologic settings. In some areas USDWs can extend much greater depths than would be appropriate for setting of surface casing. Regulations should recognize these situations and allow a surface casing setting depth that may not fully cover the USDWs.

Response: Section 146.86(b)(3) requires that the long-string casing extend to the injection zone and be cemented by circulating cement to the surface in one or more stages. It does not, however, specify how cementing would be accomplished, and gives flexibility to the owner or operator to propose alternate methods to provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment, subject to the approval of the Director. EPA notes that there are many potential ways to meet the requirement in deep wells, such as the use of staged cementing. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA adds that cementing of deep wells has been performed successfully in the past, for example, by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing requirements for long-string casing as Class VI wells, are up to 12,000 feet deep (EPA, 2001).

EPA also received comments from stakeholders representing states, a water association, and industry supporting this provision, saying that it provides, at a reasonable cost, corrosion protection of the casing; prevents undesirable migration of fluids behind the casing; provides support to the casing; and provides multiple barriers against endangerment of USDWs.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24338
Comment: EPA should delete the proposed design requirement for a surface casing cemented from the base of USDWs to the surface. While this is a commonly-imposed requirement and is generally appropriate, there are some conditions (e.g., when the base of the lowermost USDW is particularly deep) where such a requirement would be unduly burdensome and inappropriate. Accordingly, the need for surface casing to extend all the way through the base of the lowermost USDW should be left to the discretion of the permit writer rather than being predetermined in

the text of the rule.

Response: EPA disagrees that the requirement should be deleted and believes that the regulationsallow appropriate flexibility regarding the surface casing. The GS final rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of single or multiple strings of casing and cement. It does not, however, specify how cementing would be accomplished, and gives flexibility to the owner or operator to propose alternate methods to provide a sufficient amount of cement to meet the standard that USDWs are protected. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing. EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24448 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(2)

Proposed CCS Group Recommendations: (2) Surface casing must extend through the
base of the lowermost USDW ABOVE THE INJECTION ZONE and be cemented to the
surface EXCEPT THAT THE DIRECTOR MAY APPROVE A COMBINATION OF CEMENTED

SURFACE

CASING AND CEMENTED LONG STRING CASING TO ACHIEVE CONTINUOUS CEMENT

FROM THE

SURFACE THROUGH THE BASE OF THE LOWERMOST USDW ABOVE THE INJECTION

ZONE.

Basis for CCS Group Comments: Surface casing need not be cemented through the base of the lowermost USDW if a combination of cement on the surface casing and long-string casing achieves continuous cement through the base of the lowermost USDW above the injection zone. In some parts of the US, USDWs are very deep and this standard may preclude geologic sequestration at otherwise appropriate sites

in these areas.

Response: EPA believes that the regulations allow appropriate flexibility regarding the surface casing. The GS final rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single or multiple strings of casing and cement. It does not, however, specify how cementing would be accomplished, and gives flexibility to the owner or operator to propose alternate methods to provide a sufficient amount of cement to meet the standard that USDWs are protected. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

The Director will evaluate the appropriateness of the owner or operator's proposed well construction procedures based on site-specific information about the injection project, including injectionpressures, injection and confining zone lithology, and information about the carbon dioxide stream as provided in §146.86(b)(1). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

As described above, EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24521
Comment: Rule Provisions or Federal Register Cite: 146.86(b) EPA Preamble Question: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval. EPA Notice
43509.

CSC Response: Generally the surface casing is set below the lowest USDW above the confining zone, but it should be recognized that this is not appropriate in all geologic settings. In some areas USDWs can extend to much greater depths than would be appropriate for setting of surface casing. Regulations should recognize these situations and allow a surface casing setting depth that may not fully cover the USDWs.

Response: Section 146.86(b)(3) requires that the long-string casing extend to the injection zone and be cemented by circulating cement to the surface in one or more stages. It does not, however, specify how cementing would be accomplished, and gives flexibility to the owner or operator to propose alternate methods to provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment, subject to the approval of the Director. EPA notes that there are many potential ways to meet the requirement in deep wells, such as the use of staged cementing. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA adds that cementing of deep wells has been performed successfully in the past, for example, by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing requirements for long-string casing as Class VI wells, are up to 12,000 feet deep (EPA, 2001).

EPA also received comments from stakeholders representing states, a water association, and industry supporting this provision, saying that it provides, at a reasonable cost, corrosion protection of the casing, prevents undesirable migration of fluids behind the casing, provides support to the casing, and provides multiple barriers against endangerment of USDWs.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24567 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: completed in the field. One of these misconceptions is the cementing requirements; both the requirement to cement to surface as well as the use of corrosion-resistant cement. It has been demonstrated that a good cement job is more important than a resistant cement, and in certain cases, the resistant cements proved more susceptible to degradation than a basic well cement. Also, research performed at SACROC has demonstrated the effectiveness of the current Class II program's cementing requirements. Many of the requirements currently proposed do not afford any extra protection to USDWs and in many cases may actually present greater risk.

Response: EPA agrees that proper cement installation is critical to maintaining injection well integrity and clarifies that the requirement at §146.86(b)(5) is that cement and cement additives must be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project. It should be noted that in Carey et al. (2007), their research on the ER- CO2 injection well at SACROC was unable to determine whether CO2 in the presence of water, dry CO2, or a CO2-brine mixture had caused the cement alteration observed. In Crow et al. (2008), the well materials studied were from a production well producing from a natural CO2 deposit that also produced associated water, so well materials were presumably exposed to CO2 in the presence of water. Meyer (2007) acknowledges the Carey study found no loss of hydraulic integrity after 30 years, but also mentions the use of acid-resistant cements in wells used for acid gas injection and where brine is encountered.

EPA is unaware of studies showing that the resistant cements proved more susceptible to degradation than basic well cement. However, the Agency clarifies that the final rule requires at §146.86(b)(5) that cement and cement additives be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project. If certain cements have been shown to degrade, they may not be used in Class VI wells.

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 anticipates further findings in the use of acid-resistant cements, in particular the physical integrity of such modified cements in place. The Agency plans to, every six years, collect and review data on GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24675 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(2)

Anadarko Petroleum Corporation (APC) Comments: (2) Surface casing must extend through the base of the lowermost USDW ABOVE THE INJECTION ZONE and be cemented

to the surface.

Rationale: In some parts of the US the USDW is very deep and this standard may preclude geologic sequestration in these areas.

Response: EPA disagrees with the suggested edit. As described above, EPA disagrees that the surface casing requirements in the GS rule preclude injection below deep USDWs. EPA also recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 29318 Other EPA Comment Codes and Descriptions: 3824 2.3.1.2 Cementing of long-string casing (seeking comment); 3826 2.3.1.3 Packer requirements (seeking comment)
Comment: Rule Provisions: 146.86(b) EPA Rule Issue: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval. EPA Notice 43509.

Anadarko Petroleum Corporation (APC) Response: Generally the surface casing is set below the lower USDW but it should be recognized that this is not appropriate in all geologic settings. In some areas USDWs can extend much greater depths than would be appropriate for setting of surface casing. Regulations should recognize these situations and allow for other methods of protecting USDWs

APC opposes the requirement for cementing the long string casing back to surface. Cementing requirements should focus on ensuring competent isolation and seal across the confining zone(s). Sealing the annulus between the long string and surface casing could limit an operators ability to monitor for leakage or conduct remedial operations.

Regarding packer setting depth, the director should retain discretion for allowing variation from this requirement.

Response: Section 146.86(b)(3) requires that the long-string casing extend to the injection zone and be cemented by circulating cement to the surface in one or more stages. It 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 does not believe that the cementing requirements at §146.86 would prevent monitoring, operation, and remediation of GS wells. EPA notes that there are many potential ways to meet the requirement in deep wells, such as the use of staged cementing. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA adds that cementing of deep wells has been performed successfully in the past, for example, by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing requirements for long-string casing as Class VI wells, are up to 12,000 feet deep (EPA, 2001) and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation. EPA also received comments from stakeholders representing states, a water association, and industry supporting this provision, saying that it provides, at a reasonable cost, corrosion protection of the casing; prevents undesirable migration of fluids behind the casing; provides support to the casing; and provides multiple barriers against endangerment of USDWs.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

EPA clarifies that the rule allows discretion in some areas when UIC Directors evaluate and approve the owners or operators proposed well construction plan. The Director will evaluate the appropriateness of the proposed construction based on site-specific information about the injection project. EPA believes that the use of tubing and packer in accordance with §146.86(c) will offer the best multiple-barrier protection of USDWs from endangerment. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Richard Guinn Letter ID: 0210 Commenter Organization: Eastman Chemical Company Comment ID: 22723
Comment: §146.86 Injection well construction requirements. (b) (2) "Surface casing must extend through the base of the lowermost USDW and be cemented to the surface."

We recommend striking out this requirement in its entirety. This will be prohibitively expensive in deep wells, and may not be necessary at all sites.

Response: EPA disagrees with the suggested edit. Protection of USDWs, regardless of their depth or stratigraphic location, is the primary mission and mandate of the UIC program—as specified by Congress in the SDWA—and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such a demonstration cannot be made, then the activity will not be allowed under UIC requirements or theSDWA. Water agencies commenting on the proposed rule noted that diminishing water supplies are requiring water utilities to use deeper and more saline sources, and the SDWA mandates EPA to set regulations that protect USDWs from endangerment.

The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single string or multiple strings of casing and cement. It does not, however, specify how cementing must be accomplished, and it allows the owner or operator to propose alternate methods that provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: John King Letter ID: 0211 Commenter Organization: Shell Exploration and Production Company (SEPCo) Comment ID:

22770 Other EPA Comment Codes and Descriptions: 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 requirementSEPCo 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:

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.

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 stagedcementing. 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).

Commenter Name: Tiffany Rau Letter ID: 0224 Commenter Organization: Hydrogen Energy International Comment ID: 21685 Other EPA Comment Codes and Descriptions: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)
Comment: (iii) Long String Casing Is Not Needed

Section 146.86(b)(3) states that "at least one long string casing . . . must extend [from the surface] to the injection zone and must be cemented . . . ." (73 Fed. Reg. at 43538; § 146.86(b)(3).) This requirement is excessive and its implementation would unnecessarily constrain the ability to undertake future potential well interventions that support downhole monitoring and well remediation, if such become necessary.

To avoid such an unintended result, HEI recommends that EPA not mandate the placement of an isolation casing string from the surface, but rather allow the casing string to extend from beneath the surface or otherwise based upon site characteristics. Cement should cover the uppermost caprock (within the Area of Review) by approximately 500 feet; cement coverage should not be required all the way to surface. The ultimate decision for each project should rest with the Director since each storage site is unique in the geological intervals of the caprock(s), injection zone(s) and position relative to USDW(s). Moreover, any expectation to cement in the injection interval should permit the use of external casing packers or other isolation methods in conjunction with cementing requirements across the caprock, as discussed above.

Response: EPA does not believe that the cementing requirements at §146.86 would prevent monitoring and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule

for additional information.

Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.Commenter Name: Tiffany Rau Letter ID: 0224 Commenter Organization: Hydrogen Energy International Comment ID: 21689
Comment: Related to the depth of injection, HEI also disagrees with the requirement in section 146.86(b)(2) that "(s)urface casing must extend through the base of the
lowermost USDW and be cemented to the surface." One reason is that at certain potential storage sites USDWs may be located at depth; consequently, it would be technologically infeasible to construct surface casing to the requisite depth prescribed by the Proposed Rule.

Response: The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single string or multiple strings of casing and cement. It does not, however, specify how cementing must be accomplished, and allows the owner or operator to propose alternate methods that provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

EPA stresses that protection of USDWs from endangerment, regardless of their depth or the number of USDWs in an area, is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, the activity will not be allowed under UIC requirements or the SDWA.

Commenter Name: Brian Williams Letter ID: 0225 Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21736 Other EPA Comment Codes and Descriptions: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)
Comment: (iii) Long String Casing Is Not Needed

Section 146.86(b)(3) states that "at least one long string casing . . . must extend [from the surface] to the injection zone and must be cemented . . . ." (73 Fed. Reg. at 43538; § 146.86(b)(3).) This requirement is excessive and its implementation would unnecessarily constrain the ability to undertake future potential well interventions that support downhole monitoring and well remediation, if such become necessary.

To avoid such an unintended result, BP recommends that EPA not mandate the placement of an isolation casing string from the surface, but rather allow the casing string to extend from beneath the surface or otherwise based upon site characteristics. Cement should cover the uppermost caprock (within the Area of Review) by approximately 500 feet; cement coverage should not be required allthe way to surface. The ultimate decision for each project should rest with the Director since each storage site is unique in the geological intervals of the caprock(s), injection zone(s) and position relative to USDW(s). Moreover, any expectation to cement in the injection interval should permit the use of external casing packers or other isolation methods in conjunction with cementing requirements across the caprock, as discussed above.

Response: EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Brian Williams Letter ID: 0225 Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21740
Comment: Related to the depth of injection, BP also disagrees with the requirement in section 146.86(b)(2) that "(s)urface casing must extend through the base of the
lowermost USDW and be cemented to the surface." One reason is that at certain potential storage sites USDWs may be located at depth; consequently, it would be technologically infeasible to construct surface casing to the requisite depth prescribed by the Proposed Rule.

Response: The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single string or multiple strings of casing and cement. It does not, however, specify how cementing must be accomplished, and allows the owner or operator to propose alternate methods that provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

EPA stresses that protection of USDWs from endangerment, regardless of their depth or the number of USDWs in an area, is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, the activity will not be allowed under UIC requirements or the SDWA.Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24036 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language; 3824 2.3.1.2 Cementing of long-string casing (seeking comment)
Comment: Proposed Rule: (2) Surface casing must extend through the base of the lowermost
USDW and be cemented to the surface.

Schlumberger Suggested Revision: (2) Surface casing must extend through the base of the lowermost USDW above the injection zone and be cemented to the surface.

Schlumberger Rationale: In some parts of the US the USDW is very deep and this standard may preclude geologic sequestration in these areas.

Response: EPA disagrees with the suggested edit or that the surface casing requirements in the GS rule preclude injection below deep USDWs. The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single or multiple strings of casing and cement. It does not, however, specify how cementing must 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. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23236 Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost USDW
Comment: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval. EPA Notice 43509.

Requiring setting surface casing below the lowermost USDW would preclude injection above the lowermost USDW, which as earlier stated, would eliminate a vast number of potential sequestration zones. Enhanced recovery operations above the lowermost USDW have been taking place for a very long time. Exclusion of these zones where other abundant supplies of freshwater are available may unnecessarily limit sequestration options. These situations are best handled locally where the regional geologic factors can be considered. Setting the surface casing below the lowermost USDW may not be technically feasible.

Response: EPA disagrees that the surface casing requirements in the GS rule preclude injection below deep USDWs. The final GS rule at §146.86(b)(2) requires that surface casing extend throughthe base of the lowermost USDW and be cemented to the surface through the use of a single string or multiple strings of casing and cement. It does not, however, specify how cementing must be accomplished, and it allows the owner or operator to propose alternate methods that provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

EPA stresses that protection of USDWs from endangerment, regardless of their depth or the number of USDWs in an area, is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, the activity will not be allowed under UIC requirements or the SDWA.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23287 Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost USDW
Comment: 146.86(b)2 Requiring setting surface casing below the lowermost USDW would preclude injection above the lowermost USDW, which as earlier stated, would eliminate a vast number of potential sequestration zones. Enhanced recovery operations above the lowermost USDW have been taking place for a very long time. Exclusion of these zones where other abundant supplies of freshwater are available may unnecessarily limit sequestration options. These situations are best handled locally where the regional geologic factors can be considered. Setting the surface casing below the lowermost USDW may not be technically

feasible.

Response: EPA disagrees that the surface casing requirements in the GS rule preclude injection below deep USDWs. The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single or multiple strings of casing and cement. It does not, however, specify how cementing must 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. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA adds that protection of USDWs is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such a demonstration cannot be made, then the activity will not be allowed under UIC requirements or the SDWA.EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24902 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (2) Surface casing must extend through the base of the lowermost
USDW and be cemented to the surface.

GWPC Recommendations: (2) Surface casing must extend through the base of the lowermost USDW above the injection zone and be cemented to the surface.

Rationale: Insert "above the injection zone" in (2) after "USDW." In some parts of the US the USDW is very deep and this standard may preclude geologic sequestration in these areas. EPA should consider allowing the Director to exercise discretion to approve alternative means of achieving continuous cement
around the well in such areas.

Response: EPA disagrees with the suggested edit or that the surface casing requirements in the GS rule preclude injection below deep USDWs. The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single or multiple strings of casing and cement. It does not, however, specify how cementing must 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. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA adds that protection of USDWs is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such a demonstration cannot be made, then the activity will not be allowed under UIC requirements or the SDWA.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Steven Chester Letter ID: 0264Commenter Organization: Michigan Department of Environmental Quality (MDEQ) Comment ID:

22837 Other EPA Comment Codes and Descriptions: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)
Comment: EPA (III. A. 3.) proposes a surface casing and long-string casing for a GS well.

- Staff believes an intermediate casing string should be mandated for those areas where such casing is appropriate; for example, where high-pressure gas is known or suspected to exist between the surface casing and the sequestration interval. Such casings should be required to be cemented to

surface.

Response: EPA disagrees that specific requirements for intermediate casing strings should be included for all Class VI wells. The rule allows for more than one long-string casing to the injection zone in §146.86(b)(3), in essence permitting intermediate casings.

EPA acknowledges that circumstances such as the presence of high-pressure gas could dictate the use of more than one long-string casing and in this case, each would be required to be cemented from the bottom of the hole to the surface resulting in multiple barriers of cement and casing between formations above the injection zone and the fluids being injected. With their permit applications, owners or operators must submit well construction procedures, as specified in §146.82 (a)(12), that demonstrate that the well, as constructed, will prevent unacceptable fluid movement, as specified in §146.86(a). The Director will evaluate the procedures in the context of other data about the site and may require intermediate casing if it is warranted to protect USDWs from endangerment.

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.

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



### Individual Comments

Commenter Name: Michael H. Cochran Letter ID:

0108 Commenter Organization: Bureau of Water, Division of Environment, Kansas Department of Health & Environment (KDHE) Comment

ID: 21973
Comment: 146.86 (b)(3): KDHE strongly supports the requirement to cement the longstring casing from the bottom of the casing to the surface. This provides at a reasonable cost corrosion protection of the casing, prevents undesirable migration of fluids behind the casing, provides support to the casing and adds another layer of protection of the public health, safety and environment.

Response: EPA acknowledges the comment and agrees that the requirement for long-string casing of Class VI wells at §146.86(b) will offer the best protection against fluid movement behind the casing, between formations, and above the injection zone and will ensure competency of Class VIwells and protect USDWs from endangerment. The buoyant nature of CO2 dictates deep well construction procedures that address movement of fluid behind the casing and provide necessary barriers to CO2 leakage outside of the injection zone. In developing the construction requirements for Class VI wells, EPA reviewed the work cited by Carey et al. (2007) and Crow et al. (2008). EPA agrees that they offer important justification for the establishment of tailored requirements.

Commenter Name: Brian Williams Letter ID: 0116 Commenter Organization: BP Alternative Energy Comment ID: 22052
Comment: Cement across long string casing -- BP does not agree with the requirement for a long string from the injection interval to surface or with cementing across that
entire distance. Allowance should be made for a liner to be set across the injection interval when the previous string is set above that zone. Cement should cover the uppermost caprock in the Area of Review by a margin of approximately 500 feet, not to surface. The ultimate decision for each project should rest with the Director since each is unique in the geological intervals of the caprock(s) and injection zone(s) and of the position relative to USDW(s). Any expectation to cement in the injection interval should permit the use of external casing packers in conjunction with the cementing requirements across the caprock.

Response: The final GS rule at §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 adds that, under §146.86(b)(4), the Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the cement does not allow fluid movement behind the wellbore.

The construction requirements at §146.86 offer flexibility to the owner or operator to propose well construction procedures that are appropriate to the site-specific conditions of the project. With their permit applications, operators must submit well construction procedures, as specified at §146.82(a)(12), that demonstrate that the well as constructed will prevent unacceptable fluid movement; allow the use of appropriate testing devices and workover tools; and allow continuous monitoring of the annulus space between the injection tubing and long-string casing, as specified at §146.86(a). The Director will evaluate the proposed well construction procedures in the context of other data about the site. EPA has evaluated the cementing requirements for other well classes and believes that flexibility can be afforded while ensuring that USDWs are protected.

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.

Commenter Name: Doug Louis Letter ID: 0121 Commenter Organization: Kansas Corporation Commission Comment ID: 22080
Comment: The proposed rule requires the long-string casing to be cemented in place along its entire length. In a significant area of Kansas, cement cannot be circulated to surface in the borehole-casing annulus on the primary cementing job. Toaccomplish a continuous cemented interval would involve numerous pipe perforations and cement squeezing operations. This additional "remedial" work sacrifices mechanical integrity of the pipe for a marginal possibility of additional isolation of the injection zone. Considering these unique conditions and associated risk, Kansas’ regulations prescribe an interval of 500 feet of cemented interval above the injection zone. KCC staff believes an exotic blend

Response: The final GS rule at §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 adds that, under §146.86(b)(4), the Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the cement does not allow fluid movement behind the wellbore.

The construction requirements at §146.86 offer flexibility to the owner or operator to propose well construction procedures that are appropriate to the site-specific conditions of the project. With their permit applications, operators must submit well construction procedures, as specified at §146.82(a)(12), that demonstrate that the well as constructed will prevent unacceptable fluid movement; allow the use of appropriate testing devices and workover tools; and allow continuous monitoring of the annulus space between the injection tubing and long-string casing, as specified at §146.86(a). The Director will evaluate the proposed well construction procedures in the context of other data about the site. EPA has evaluated the cementing requirements for other well classes and believes that flexibility can be afforded while ensuring that USDWs are protected.

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.

Commenter Name: Leslie Savage Letter ID: 0122 Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24736
Comment: - The requirement that the long-string casing be cemented to the surface is equally as stringent as the Class I hazardous waste well requirements. - Annulus

Response: EPA clarifies that the requirements for Class VI wells are not necessarily more stringent than those for Class I hazardous waste injection wells; rather, they are different. For example, Class I hazardous well owner or operators are subject to requirements that are not applicable to Class VI wells, such as no migration petitions.

Commenter Name: Leslie Savage Letter ID: 0122 Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24746 Other EPA Comment Codes and Descriptions: 1250 1.1.1.4 Flexibility is needed (performancebased standards)
Comment: 4. EPA should provide more flexibiilty in construction, for example, delete the requirement that the long string casing be cemented to the surface.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).

Commenter Name: Leslie Savage Letter ID: 0122 Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24785 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages.

{Circulation of cement unnecessary and more stringent that requirement for Class I hazardous waste wells. RRC suggests that it may not be technically feasible to cement the full column of one long string casing because the formations you likely want to inject into are low-pressure, and typically won't hold a full column of cement, making circulation impossible. RRC suggests a certain footage of cement, such as 600 ft, and require a bond log to verify it. }

Response: EPA believes that the construction requirements at §146.86 offer flexibility to the owner or operator to propose well construction procedures that are appropriate to the site-specific conditions of the project. Section 146.86(b)(3) requires that the long-string casing extend to the injection zone and be cemented by circulating cement to the surface in one or more stages. It 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.

EPA believes that current cementing technology can address deep well cement columns or lowpressure bottom-of-hole formations. The oil and gas industry has experience drilling and cementing wells in very deep formations and in formations with low pressures. Less dense, lighter weight cement slurries that include nitrogen foam or lightweight microspheres (Sabins 2002; Kulakofsky etal. 2005) are used to prevent breakdown of the low pressure formation and loss of circulation. Another way to approach low formation pressure conditions is with reverse cementing (pumping the cement into the annulus and returning it through the casing). This method uses gravity to place the cement and bypass lost circulation zones. Reverse cementing can be combined with other methods such as foam cement. Ten successful reverse-cemented wells have been completed in a variety of onshore/offshore environments (Chase 2008).

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.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141 Commenter Organization: Global Energy, Inc. Comment ID: 23111 Other EPA Comment Codes and Descriptions: 3822 2.3.1.1 Depth of surface casing (seeking comment)
Comment: 1.We support the basic and conservative installation criteria proposed. We question whether casing to the injection horizon, cementing the full length is really necessary. It seems certain that experts in geology and well installation should have the latitude to determine the appropriate installation method. Appropriate instrumentation and shut-offs are reasonable.

Response: EPA believes that the requirements for surface and long-string casing are necessary and also that they offer appropriate flexibility. The final GS rule requires, at §146.86(b)(2), that the surface casing must extend through the base of the lowermost USDW and be cemented to the surface, and that at least one long string casing must be cemented to the surface in one or more stages at §146.86(b)(3). 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).

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22556 Other EPA Comment Codes and Descriptions: 3822 2.3.1.1 Depth of surface casing (seekingcomment)
Comment: specific considerations. All injection wells should be cased and cemented to stop fluid movement between formations. A surface casing should be installed and set below the lowermost USDW above the injection zone and cemented along its entire length. It is important when considering the height of the cement sheath behind the long-string casing to consider the overall "design" of the injection and monitoring zones. Because, it is ideal to have a secondary caprock it will be imperative to cement the well, at a minimum, from the injection zone to a level above the secondary confining unit. If the borehole through the secondary caprock is left uncemented the effectiveness of the secondary caprock will be greatly reduced. Furthermore, it may be advisable to cement the casing along the entire length to protect the casing from degradation due to anodic dissolution [Anstice et al., 2005] or exposure to corrosive formation fluids. If the casing is not cemented along its entire length it may be necessary to use cathodic protection, depending on the site, to keep the casing from degrading. Watson and Bachu, [2007] found that about 81% of wells in their study area that had surface casing vent flows (leaks) had them above the top cemented section.

Anstice, D.J., Page, C.L., and Page, M.M., 2005, "The pore solution phase of carbonated cement pastes," Cement and Concrete Research, Vol. 35, pp. 377-383.

Watson, T.L. and Bachu, S., "Evaluation of the potential for gas and CO2 leakage along wellbores," paper SPE 106817 presented at the 2007 E&P Environmental and Safety Conference, Galveston, TX, March 5-7, 2007.

Response: EPA agrees that the casing should be cemented along its entire length. The final GS rule requires, at §146.86(b)(2), that the surface casing must extend through the base of the lowermost USDW and be cemented to the surface, and that at least one long string casing must be cemented to the surface in one or more stages at §146.86(b)(3). EPA believes that these requirements are an important component of construction that will protect USDWs from endangerment.

Cathodic protection can also be used to control corrosion, even when the long-string casing is fully cemented. Though not required for all wells, additional techniques like cathodic protection may be required by the Director if he/she determines they are necessary at a specific location to ensure protection of USDWs. EPA adds that the Director also has the authority to require a casing inspection log, as specified at §146.89(d), which can be used to determine the presence or absence of corrosion of the long-string casing and can give early warning of casing problems with corrosion.

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.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22602 Other EPA Comment Codes and Descriptions: 3822 2.3.1.1 Depth of surface casing (seeking comment)
Comment: Proposed Rule: 146.86(b)(3)Comment: NGWA supports this provision

Response: EPA disagrees that protecting deep USDWs underlying multiple, more shallow USDWs is "overkill." Protection of USDWs, regardless of their depth or stratigraphic location, is the primary mission and mandate of the UIC program—as specified by Congress in the SDWA—and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such a demonstration cannot be made, then the activity will not be allowed under UIC requirements or the SDWA. Water agencies commenting on the proposed rule noted that diminishing water supplies are requiring water utilities to use deeper and more saline sources, and the SDWA mandates EPA to set regulations that protect USDWs from endangerment.

The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single string or multiple strings of casing and cement. It does not, however, specify how cementing must be accomplished, and it allows the owner or operator to propose alternate methods that provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Larry Myer Letter ID:
0149 Commenter Organization: Lawrence Berkeley National Laboratory (Berkeley Lab) U.S. Department of Energy (DOE) Comment ID:

21799
Comment: Setting the interval for cementing of the casing as the entire casing lengthl seems arbitrary and unjustified. A conservative cementing program is justified. It is unclear, however, why 4000 ft of cement is sufficient for a 4000 ft deep well and insufficient for a 10,000 ft deep well. For very deep wells the costs and difficulties in cementing the entire casing length go up dramatically. The risks of loosing the whole well also increase significantly with the increased difficulty of the operation. Of highest priority is a high quality cement bond through the formation(s) forming the primary seal of the storage reservoir. Beyond that, cementing should not be required beyond that which is practical in a single stage cementing program.

Response: EPA disagrees that the construction requirements for Class VI wells at §146.86 are arbitrary or unjustified. The final GS rule requires, at §146.86(b)(2), that the surface casing must extend through the base of the lowermost USDW and be cemented to the surface, and that at least one long string casing must be cemented to the surface in one or more stages at §146.86(b)(3). It does not, however, specify how cementing must be accomplished, and it allows the owner or operator to propose alternate methods that provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment. EPA notes that there are many potentialways to meet the requirement, such as the use of staged cementing.

The Class VI well requirements address the unique nature of CO2 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 adds that cementing of deep wells has been performed successfully in the past, for example, by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing requirements for long-string casing as Class VI wells, are up to 12,000 feet deep (EPA, 2001).

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Bonnie Lovelace Letter ID: 0152 Commenter Organization: Montana Department of Environmental Quality (MDEQ) Comment ID:

22130
Comment: 146.86(b)(3): MDEQ supports the cementing requirement for the length of long string casing from the bottom to the surface. This precaution protects the casing from corrosion and the impacts of such corrosion including failure of the seal that would allow migration of fluids.

Response: EPA agrees that the requirement for long-string casing of Class VI wells at §146.86(b) will offer the best protection against fluid movement behind the casing, between formations, and above the injection zone and will ensure competency of Class VI wells and protect USDWs from endangerment. The buoyant nature of CO2 dictates deep well construction procedures that address movement of fluid behind the casing and provide necessary barriers to CO2 leakage outside of the injection zone. In developing the construction requirements for Class VI wells, EPA reviewed the work cited by Carey et al. (2007) and Crow et al. (2008). EPA believes that they offer important justification for the establishment of tailored requirements.

Commenter Name: Steven Pirner Letter ID: 0153 Commenter Organization: South Dakota Department of Environment and

Natural Resources Comment ID:

22149
Comment: (b) (3) at least one long string must extend to the injection zone and be cemented to the surface - same as comment for (b) (2) previous - especially if tubing is cemented from top to bottom, and long string is cemented into surface casing.

Response: As described above, EPA believes that protection of USDWs, regardless of their depth or stratigraphic location, is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells.

The final GS rule at §146.86(b)(3) requires that the long-string casing extend to the injection zoneand 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 recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Michael J. Miller Letter ID: 0168 Commenter Organization: Electric Power Research Institute (EPRI) Comment ID: 22502
Comment: Preamble, page 43509: "EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval."

EPRI COMMENT #8: Cementing the entire length of the long-string casing is not standard practice in the oil and natural gas industry and not adequately justified by EPA in the preamble to the rule. Compared to CO2, natural gas is highly flammable and, in the absence of pressure gradients, much more buoyant because of its lower density and higher mobility in the formation. In contrast, during CO2 injection, where pressure gradients are large and buoyancy effects are comparatively small, models show that CO2 dries out the formation around the well (Pruess and Spycher, 2006), significantly lowering the risk of cement corrosion. Therefore, cementing standards adopted for natural gas wells designed to be protective of USDWs should be more than adequate for ensuring safe and permanent sequestration of the injected CO2. Wellbore conditioning prior to cementing and a well designed and executed cementing operation have greater impact on the cement integrity than the overall length of the cement seal. EPRI encourages the EPA to develop and adopt less stringent cementing requirements for the long-string casing, consistent with natural gas wells currently in use. (See for example, Chapter 4 Development, Regulation, and Conservation of Oil and Gas Resources, Article 3 Requirements, Section 1722.4 Cementing Casing, in the State of California, California Code of Regulations, Title 14: Natural Resources; Division 2: Department of Conservation, Publication No. PRC04).

Pruess, K. and N. Spycher, 2006. ECO2N - A New TOUGH2 Fluid Property Module for Studies of CO2 Storage in Saline Aquifers, Proceedings: TOUGH Symposium 2006, Lawrence Berkeley National Laboratory, Berkeley, California, May 15-17, 2006.

Response: EPA disagrees that the construction requirements for Class VI wells at §146.86 are not justifiable. The Class VI well requirements address the unique nature of CO2 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), and were informed by numerous stakeholder workshops, EPA and DOE research, and oil and gas industry studies on well construction. EPA adds that commenters representing states, awater association, and industry supported this provision, saying that the requirement provides, at a reasonable cost, corrosion protection of the casing; prevents undesirable migration of fluids behind the casing; provides support to the casing; and provides multiple barriers against endangerment of USDWs. EPA adds that cementing of deep wells has been performed successfully in the past, for example, by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing requirements for long-string casing as Class VI wells, are up to 12,000 feet deep (EPA, 2001).

EPA recognizes that the GS rule includes requirements (e.g., cementing the entire length of the longstring casing) that are not standard practice in the oil and natural gas industry, but believes that there are significant operational differences between ER and GS. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will 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. In addition, CO2 in the presence of water may be corrosive to well materials. For these reasons, 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.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24127
Comment: Furthermore, some of the proposed requirements - such as cementing the long string casing to surface and use of down-hole shut-off valves - are not only unnecessarily burdensome, but might also interfere with operations, may not serve their intended purpose, and could introduce unintended risks. For example, cementing the longstring casing to surface seals off access to the annulus which could otherwise be used to monitor subsurface formations for potential leakage.

Response: EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation, and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24175 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(3)

API Comments: (3) At least one long string casing, using a sufficient number

of centralizersSET IN A MANNER SO AS TO CREATE A CEMENT BOND THROUGH THE INJECTION AND CONFINING ZONE(S). THE LONG STRING CASING must extend to the injection zone and must be cementedISOLATED by circulating cement to thesurface in one or more stages. PLACING CEMENT AND/OR OTHER ISOLATION TECHNOLOGIES AS NECESSARY TO PROVIDE ADEQUATE ISOLATION OF THE

INJECTION ZONE

AND PROVIDE FOR PROTECTION OF USDWS.

Rationale: Cementing to surface is not necessary to protect USDWs, and may have negative consequences, as follows. Cement to surface would eliminate the ability to monitor pressures in this annulus and would limit flexibility of remedial options. As revised, the proposal would allow for application and development of alternative technologies. See API RP90 for description of risk-based approach for managing situations involving annular casing pressure. Industry experience with CO2 EOR under the Class II program demonstrates the effectiveness of existing cementing procedures.

Rule Provision: 146.86(b)(4)

API Comments: (4) Circulation of cement may be accomplished by staging. The Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the cement does not allow fluid movement behind
the well bore.

Rationale: Same as above

Response: EPA disagrees with the suggested edits. EPA believes that the requirements for longstring casing are appropriate and offer appropriate flexibility: §146.86(b)(3) requires that the longstring 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 stresses that protection of USDWs is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, then the activity will not be allowed under UIC requirements or the SDWA.

EPA disagrees that the requirement at §146.86(b)(4) should be deleted. Section 146.86(b)(4) of the final rule allows alternate methods of staging the cement, at the Director's discretion, provided the owner or operator can demonstrate using logs that the cement does not allow fluid movement behind
the wellbore.

EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation, and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VIwells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 29257
Comment: Rule Provisions: 146.86(b) EPA Preamble Question: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval. EPA Notice
43509.

API opposes the requirement for cementing the long string casing back to surface. Cementing requirements should focus on ensuring competent isolation and seal across the injection zone and confining zone(s). Sealing the annulus between the long string and surface casing could limit an operators ability to monitor for leakage or conduct remedial operations.

Response: As described above, EPA believes that the requirements for long-string casing are appropriate and offer appropriate flexibility. EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation, and remediation of GS wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Kenneth Nemeth Letter ID: 0176 Commenter Organization: Southern States Energy Board Comment ID: 23544
Comment: Injection well construction details should be consistent with Class II CO2 EOR experiences and operations and not unnecessarily burdensome to an owner/operator of a GS project. Continuous cementation from base to surface of the long-string casing should not be required. No specific timeframe for post closure care

Response: 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. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will 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. Therefore, Class VI GS reservoir pressures will increase more in comparison to Class II ER during the injection phase of the GS project.

EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced recovery and that many of the wells used for ER may be suitable for GS. The final GS rule, at §146.81(c), allows the construction of these wells to be grandfathered, provided the owner or operator can demonstrate to the Director that the wells were engineered and constructed tomeet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). Only the cemented-in-place construction requirements would be grandfathered under the final GS rule; following conversion, these wells must be permitted as Class VI wells and be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final GS rule.

The final GS rule requires, at §146.86(b)(2), that the surface casing must extend through the base of the lowermost USDW and be cemented to the surface, and that at least one long string casing must be cemented to the surface in one or more stages at §146.86(b)(3). It does not, however, specify how cementing must be accomplished, and it allows the owner or operator to propose alternate methods that provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing. 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24340
Comment: EPA should delete the proposed design requirement for the long-string casing to be cemented to the surface. Such a requirement - while arguably appropriate in the case of hazardous waste injection wells - can significantly complicate well construction, testing and repair, and is too costly to justify in the case of CO2 injection. Cement must of course be sufficient to prevent endangerment of USDWs, but the specific measures necessary to achieve this performance standard are dependent on site-specific conditions and are most appropriately determined in the permitting process rather than being predetermined in the text of the

rule.

Response: EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation, and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24447 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(1)(viii)

Proposed CCS Group Recommendations: (viii) Type or grade of cement AND ADDITIVES; andBasis for CCS Group Comments: Technical revision

Response: EPA agrees with the suggestion that §146.86(b)(1)(viii) be revised to also address cement additives. In the final GS rule, the subparagraph reads as follows: "Type or grade of cement and
cement additives."

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24449 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(3)

Proposed CCS Group Recommendations: (3) At least one long string casing, using

a sufficient number of centralizersSET IN A MANNER SO AS TO CREATE A CEMENT BOND THROUGH THE INJECTION AND CONFINING ZONE(S). THE LONG STRING

CASING must extend to the injection zone and must be cementedISOLATED by circulating cement to the surface in one or more stages. PLACING CEMENT AND/OR OTHER ISOLATION TECHNOLOGIES AS NECESSARY TO PROVIDE ADEQUATE ISOLATION OF

THE
INJECTION ZONE AND PROVIDE FOR PROTECTION OF USDWS.

Basis for CCS Group Comments: Cementing of the long string casing to surface is not necessary to protect USDWs, and may have negative consequences. Cement to surface would eliminate the ability to monitor pressures in this annulus and would limit flexibility of remedial options. As revised, the proposal would allow for application and development of alternative technologies. See API RP90 for description of risk-based approach for managing situations involving annular casing pressure. Industry experience with CO2 EOR under the Class II program demonstrates the effectiveness of existing cementing procedures.

Response: EPA disagrees with the suggested edits. EPA believes that the requirements for longstring casing are appropriate and offer appropriate flexibility: §146.86(b)(3) requires that the longstring 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 stresses that protection of USDWs is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, then the activity will not be allowed under UIC requirements or the SDWA.

EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation, and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner thatmaintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24450 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(4)

Proposed CCS Group Recommendations: (4) Circulation of cement may be accomplished by staging. The Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the cement
does not allow fluid movement behind the well bore.

Basis for CCS Group Comments: Same as above

Response: EPA disagrees that the requirement should be deleted. Section 146.86(b)(4) of the final rule allows alternate methods of staging the cement, at the Director's discretion, provided the owner or operator can demonstrate using logs that the cement does not allow fluid movement behind the
wellbore.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 29259
Comment: Rule Provisions or Federal Register Cite: 146.86(b) EPA Preamble Question: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval. EPA Notice
43509.

CSCopposes the requirement for cementing the long string casing back to surface. Cementing requirements should focus on ensuring competent isolation and seal across the injection zone and confining zone(s). Sealing the annulus between the long string and surface casing could limit an operators ability to monitor for leakage or conduct remedial operations.

Response: EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation, and remediation of GS wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirementsas Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: John R. Baza Letter ID: 0193 Commenter Organization: Utah Division of Oil, Gas, and Mining Comment ID: 23913 Other EPA Comment Codes and Descriptions: 3820 2.3.1 Well construction procedures
Comment: Proposed Well Construction Requirements

EPA proposed that construction of GS wells be tailored to the construction requirements of a Class IH well. The Division agrees that USDWs need to be protected; however, these construction requirements may be too stringent for existing Class II EOR wells. To require remedial work on existing wells to achieve the proposed standards may in fact compromise the established mechanical integrity of an existing Class II well. Additionally, the requirement to set surface casing and cement through the base of the lowermost aquifer would be too restrictive. The regulating agency should have the discretion to evaluate wells on a site-specific basis to insure that USDWs will be protected.

Response: EPA disagrees that the well construction standards for Class VI wells are too stringent. Rather, the construction requirements at §146.86 provide an appropriate level of protection from endangerment to USDWs that is based upon the existing UIC framework for deep wells. The new tailored approach was designed to address the general risks deep injection may pose to USDWs and was tailored specifically to address the unique nature of CO2 GS (i.e., 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 adds that promoting GS or carbon management efforts is outside the scope of the GS rulemaking, which focuses on protecting USDWs from endangerment.

Regarding the comment that remedial work will compromise the mechanical integrity of an existing Class II well, EPA clarifies that if a Class II well cannot be converted for GS injection and operated in a way that protects USDWs, including maintaining mechanical integrity and safe operation, conversion to Class VI will not be allowed. EPA believes that many Class II wells are constructed in a manner that would allow conversion for use as Class VI wells, but acknowledges that this may not
be the case for all such wells.

The final GS rule, at §146.81(c), allows the construction of ER wells to be grandfathered, 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). Only the cemented-in-place construction requirements will be grandfathered under the final GS rule; following conversion, these wells will be permitted as Class VI wells and be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final GS rule.

EPA is developing guidance on transitioning from Class II to Class VI. The guidance will assist Directors and owner/operators in evaluating where a project may fit within a Class II to Class VItransition. The guidance describes the methods available for the Director to determine the risk posed to USDWs from a GS/ER project, and how the Director may determine if a project should be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24676 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(3)

Anadarko Petroleum Corporation (APC) Comments: (3) At least one long string casing, using a sufficient number of centralizers TO CREATE A CEMENT BOND THROUGH THE INJECTION AND CONFINING ZONE(S), must extend to the injection zone

and must be cementedISOLATED by circulating cement to the surface in one
or more stages. PLACING CEMENT AND/OR OTHER ISOLATION TECHNOLOGIES AS NECESSARY TO PROVIDE ADEQUATE ISOLATION OF THE INJECTION ZONE AND

PROVIDE FOR

PROTECTION OF USDWS.

Rationale: Cementing to surface is not necessary to protect USDWS, and may have negative consequences, as follows. Cement to surface would eliminate the ability to monitor pressures in this annulus and would limit flexibility of remedial options. As revised, the proposal would allow for application and development of alternative technologies. See API RP90 for description of risk-based approach for managing situations involving annular casing pressure. Industry experience with CO2 EOR under the class II program demonstrates the effectiveness of existing cementing procedures.

Response: EPA disagrees with the suggested edits. EPA believes that the requirements for longstring casing are appropriate and offer appropriate flexibility: §146.86(b)(3) requires that the longstring 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 stresses that protection of USDWs is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, then the activity will not be allowed under UIC requirements or the SDWA.

EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation, and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rulefor 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.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24677 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(4)

Anadarko Petroleum Corporation (APC) Comments: (4) Circulation of cement may be accomplished by staging. The Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the cement
does not allow fluid movement behind the well bore.

Rationale: Same as above

Response: EPA disagrees that the requirement should be deleted. Section 146.86(b)(4) of the final rule allows alternate methods of staging the cement, at the Director's discretion, provided the owner or operator can demonstrate using logs that the cement does not allow fluid movement behind the
wellbore.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24678 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(5)

Anadarko Petroleum Corporation (APC) Comments: (5) Cement and cement additives

must be compatible SUITABLE FOR USE with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity
over the designOPERATING life of the geologic sequestration project WELL. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

Rationale: Experience with CO2 EOR under the class II program demonstrates the effectiveness of existing cementing materials and procedures. Standard API cements have been used in numerous CO2 EOR operations with no adverse consequences. Refer to the citations within EPA’s proposed rule 73 FR 43532- 43533: Carey et al., (2007), Crow et al., (2008), and Meyer, J.P (2007).Response: EPA disagrees with the suggested edits. 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.

EPA recognizes that the oil and gas industry has decades of experience injecting CO2 and has demonstrated the effectiveness of existing cementing materials and procedures. The final GS rule, at §146.86(b)(1), specifies that all casing and cementing or other materials used in the construction of Class VI wells must meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. This requirement invokes the expertise of these bodies to ensure that the requirements for construction of Class VI wells reflect the state of the art in well construction technology. 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 also believes that GS is sufficiently different from Class II ER operations to warrant the tailored construction requirements for Class VI wells at §146.86. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will 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. Therefore, Class VI GS reservoir pressures will increase during the injection phase of the GS project.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 29318 Other EPA Comment Codes and Descriptions: 3822 2.3.1.1 Depth of surface casing (seeking comment); 3826 2.3.1.3 Packer requirements (seeking comment)
Comment: Rule Provisions: 146.86(b) EPA Rule Issue: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval. EPA Notice 43509.

Anadarko Petroleum Corporation (APC) Response: Generally the surface casing is set below the lower USDW but it should be recognized that this is not appropriate in all geologic settings. In some areas USDWs can extend much greater depths than would be appropriate for setting of surface casing. Regulations should recognize these situations and allow for other methods of protecting USDWs

APC opposes the requirement for cementing the long string casing back to surface. Cementing requirements should focus on ensuring competent isolation andseal across the confining zone(s). Sealing the annulus between the long string and surface casing could limit an operators ability to monitor for leakage or conduct remedial operations.

Regarding packer setting depth, the director should retain discretion for allowing variation from this requirement.

Response: Section 146.86(b)(3) requires that the long-string casing extend to the injection zone and be cemented by circulating cement to the surface in one or more stages. It 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 does not believe that the cementing requirements at §146.86 would prevent monitoring, operation, and remediation of GS wells. EPA notes that there are many potential ways to meet the requirement in deep wells, such as the use of staged cementing. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA adds that cementing of deep wells has been performed successfully in the past, for example, by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing requirements for long-string casing as Class VI wells, are up to 12,000 feet deep (EPA, 2001) and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation. EPA also received comments from stakeholders representing states, a water association, and industry supporting this provision, saying that it provides, at a reasonable cost, corrosion protection of the casing; prevents undesirable migration of fluids behind the casing; provides support to the casing; and provides multiple barriers against endangerment of USDWs.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

EPA clarifies that the rule allows discretion in some areas when UIC Directors evaluate and approve the owners or operators proposed well construction plan. The Director will evaluate the appropriateness of the proposed construction based on site-specific information about the injection project. EPA believes that the use of tubing and packer in accordance with §146.86(c) will offer the best multiple-barrier protection of USDWs from endangerment. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: John King Letter ID: 0211 Commenter Organization: Shell Exploration and Production Company (SEPCo) Comment ID:

22750
Comment: - The choice of casing and cement materials should be selected based on plannedoperating 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.

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.

Commenter Name: John King Letter ID: 0211 Commenter Organization: Shell Exploration and Production Company (SEPCo) Comment ID:

22770 Other EPA Comment Codes and Descriptions: 3822 2.3.1.1 Depth of surface 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 requirementSEPCo 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:

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.

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 ofClass 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).

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24294
Comment: 2. EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells. (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages.

*

*

* (5) Cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the geologic sequestration project. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

Additional proposed requirements affecting casing and cementing of Class VI wells are set forth in §§ 146.86 (b)(3) and (5) as quoted above. The requirement to cement the casing to the surface is unnecessary, expensive and contrary to best practices. Under acceptable best practices, the long string casing would not be cemented to the surface so that the pressure between the surface casing and long string can be monitored to determine if there is migration between the long-string casing and the surface casing. The cementing requirement proposed above would limit the ability to monitor for migration of injected fluids, in this case CO2, behind the casing. Additionally, Denbury’s field data indicates that the proposed casing and cementing requirements are costly while providing limited, if any benefit. According to our findings, under existing Class II UIC rules, a conventional cementing program costs approximately $20,000 per well. Under the cementing program proposed for Class VI wells the cost could escalate to approximately $193,000 per well-a potential $173,000 increase, representing a 10% increase in total per well costs.[FN43]

Denbury suggests an alternative that protects USDWs, but at a reasonable cost. Rather than require cementing of the long string casing to the surface, the proposed rule should require cement and cement additives to be compatible with the carbon dioxide stream and formation fluids that cover the injection zone and the confining zone, and then require standard (API, ASTM International, orcomparable standards) industry cements to a certain distance above the confining zone. This would place cements that may require special additives at the point where USDWs are most effectively protected from the mixture of carbon dioxide and formation fluids that could produce carbonic acid.

[43] For a typical well completed under Class II UIC rules, the total costs equals $1,700,000.

Response: EPA acknowledges that the Class VI requirements have associated costs beyond baseline costs assumed in the cost analysis for this rule (based on an assumption that Class I industrial wells are the baseline). The Agency clarifies that the purpose of the GS regulation, promulgated under authority of the SDWA, is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.

The final cost analysis supporting the GS Rule includes cementing costs of $1.20 per foot lengthinch diameter plus 25% of total cementing costs for use of corrosion-resistant cement. For a representative deep saline injection well used in the cost analysis, this translates to a total cementing cost of $406,500 per injection well, representing an incremental cost of approximately 305,000 over baseline costs. This unit cost is in line with estimates provided by the commenter (actual costs are driven by well-specific characteristics). While the rule requirements necessitate these additional costs, the requirements are guided by the necessity to address the unique challenges posed by CO2 injection (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) as they protect USDWs from endangerment.

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24295 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Denbury suggests the following revision:

§146.86 (b) Casing and Cementing of Class VI Wells. (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement

to the surface INJECTION ZONE AND CONFINING ZONE AND AN AUTHORIZED DISTANCE ABOVE THE CONFINING ZONE, SUBMITTED BY THE

PERMITTEE
AND APPROVED BY THE DIRECTOR in one or more stages.

*

*

* (5) TO PROTECT USDWS, C cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the designOPERATING life of the WELL geologic sequestration projectMUST BE USED ACROSS THE INJECTION ZONE AND CONFINING ZONE. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.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.

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.

Commenter Name: Edward Steadman Letter ID: 0220 Commenter Organization: The Energy and Environmental Research Center at the University of North Dakota Comment ID:

21634
Comment: Page 43538. § 146.86 Injection well construction requirements. Requiring surface casing to extend below the base of the lowermost USDW precludes potential sequestration zones.

Response: EPA disagrees that the surface casing requirements in the GS rule preclude injection below deep USDWs. EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the
final GS rule for additional information.

EPA stresses that protection of USDWs from endangerment, regardless of their depth or the number of USDWs in an area, is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, the activity will not be allowed under UIC requirements or the SDWA.

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23972 Other EPA Comment Codes and Descriptions: 6100 3.1 Comments on the cost estimates
Comment: EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells. (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages.

*

*

*(5) Cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the geologic sequestration project. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

Additional proposed requirements affecting casing and cementing of Class VI wells is set forth in §§ 146.86 (b)(3) and (5) as quoted above. The requirement, to cement the casing to the surface is unnecessary, expensive and contrary to best practices. Under acceptable best practices, the long string casing would not be cemented to the surface so that the pressure between the surface casing and long string can be monitored to determine if there is migration between the long-string casing and the surface casing. The cementing requirement proposed above would limit the ability to monitor for migration of injected fluids, in this case CO2, behind the casing. Additionally, TxCCSA’s field data indicates that the proposed casing and cementing requirements are costly while providing limited, if any benefit. According to our findings, under existing Class II UIC rules, a conventional cementing program costs approximately $20,000 per well. Under the cementing program proposed for Class VI wells the cost could escalate to approximately $193,000 per well a potential $173,000 increase, representing a 10% increase in total per well costs.[FN1]

[FN1: For a typical well completed under Class II UIC rules, the total costs equals $1,700,000.]

TxCCSA suggests an alternative that protects USDWs, but at a reasonable cost. Rather than require cementing of the long string casing to the surface, the proposed rule should require cement and cement additives to be compatible with the carbon dioxide stream and formation fluids that cover the injection zone and the confining zone, and then require standard (API, ASTM International, or comparable standards) industry cements to a certain distance above the confining zone. This would place cements that may require special additives at the point where USDWs are most effectively protected from the mixture of carbon dioxide and formation fluids that could produce carbonic acid.

Response: EPA acknowledges that the Class VI requirements have associated costs beyond baseline costs assumed in the cost analysis for this rule (based on an assumption that Class I industrial wells are the baseline). The Agency clarifies that the purpose of the GS regulation, promulgated under authority of the SDWA, is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.

The final cost analysis supporting the GS Rule includes cementing costs of $1.20 per foot lengthinch diameter plus 25% of total cementing costs for use of corrosion-resistant cement. For a representative deep saline injection well used in the cost analysis, this translates to a total cementing cost of $406,500 per injection well, representing an incremental cost of approximately 305,000 over baseline costs. This unit cost is in line with estimates provided by the commenter (actual costs are driven by well-specific characteristics). While the rule requirements necessitate these additional costs, the requirements are guided by the necessity to address the unique challenges posed by CO2injection (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) as they protect USDWs from endangerment.

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23973 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: TxCCSA suggests the following revision:

§146.86 (b) Casing and Cementing of Class VI Wells. (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement

across the surface INJECTION ZONE AND CONFINING ZONE AND AN AUTHORIZED DISTANCE ABOVE THE CONFINING ZONE, SUBMITTED BY THE

PERMITTEE
AND APPROVED BY THE DIRECTOR in one or more stages.

*

*

* (5) TO PROTECT USDWS, C Cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the designOPERATING life of the WELL geologic sequestration project
MUST BE USED THROUGH THE INJECTION ZONE AND CONFINING ZONE. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

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 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. 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.

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.Commenter Name: Tiffany Rau Letter ID: 0224 Commenter Organization: Hydrogen Energy International Comment ID: 21685 Other EPA Comment Codes and Descriptions: 3822 2.3.1.1 Depth of surface casing (seeking comment)
Comment: (iii) Long String Casing Is Not Needed

Section 146.86(b)(3) states that "at least one long string casing . . . must extend [from the surface] to the injection zone and must be cemented . . . ." (73 Fed. Reg. at 43538; § 146.86(b)(3).) This requirement is excessive and its implementation would unnecessarily constrain the ability to undertake future potential well interventions that support downhole monitoring and well remediation, if such become necessary.

To avoid such an unintended result, HEI recommends that EPA not mandate the placement of an isolation casing string from the surface, but rather allow the casing string to extend from beneath the surface or otherwise based upon site characteristics. Cement should cover the uppermost caprock (within the Area of Review) by approximately 500 feet; cement coverage should not be required all the way to surface. The ultimate decision for each project should rest with the Director since each storage site is unique in the geological intervals of the caprock(s), injection zone(s) and position relative to USDW(s). Moreover, any expectation to cement in the injection interval should permit the use of external casing packers or other isolation methods in conjunction with cementing requirements across the caprock, as discussed above.

Response: EPA does not believe that the cementing requirements at §146.86 would prevent monitoring and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule

for additional information.

Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Brian Williams Letter ID: 0225 Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21736 Other EPA Comment Codes and Descriptions: 3822 2.3.1.1 Depth of surface casing (seeking comment)
Comment: (iii) Long String Casing Is Not Needed

Section 146.86(b)(3) states that "at least one long string casing . . . must extend [from the surface] to the injection zone and must be cemented . . . ." (73 Fed. Reg. at 43538; § 146.86(b)(3).) This requirement is excessive and its implementation would unnecessarily constrain the ability to undertake future potential well interventions that support downhole monitoring and wellremediation, if such become necessary.

To avoid such an unintended result, BP recommends that EPA not mandate the placement of an isolation casing string from the surface, but rather allow the casing string to extend from beneath the surface or otherwise based upon site characteristics. Cement should cover the uppermost caprock (within the Area of Review) by approximately 500 feet; cement coverage should not be required all the way to surface. The ultimate decision for each project should rest with the Director since each storage site is unique in the geological intervals of the caprock(s), injection zone(s) and position relative to USDW(s). Moreover, any expectation to cement in the injection interval should permit the use of external casing packers or other isolation methods in conjunction with cementing requirements across the caprock, as discussed above.

Response: EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24033
Comment: Proposed Rule: (1) Casing and cement or other materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the life of the geologic sequestration project. All well materials must be compatible with fluids with which the materials may be expected to come into contact and meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. The casing and cementing program must be designed to prevent the movement of fluids into or between USDWs. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information:

Schlumberger Suggested Revision: -

Schlumberger Rationale: We support this language as written.

Response: EPA agrees that cement that is compatible with the CO2 and formation fluids will enhance Class VI well integrity and has retained this provision in the final rule. EPA also agrees that developing technology in the field of acid-resistant cement will provide the industry with future benefits. In the interest of USDW protection, the Agency requires that the materials used in Class VI wells must be compatible with fluids with which they may come in contact, as required in §146.86(b)(1).Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24036 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language; 3822 2.3.1.1 Depth of surface casing (seeking comment)
Comment: Proposed Rule: (2) Surface casing must extend through the base of the lowermost
USDW and be cemented to the surface.

Schlumberger Suggested Revision: (2) Surface casing must extend through the base of the lowermost USDW above the injection zone and be cemented to the surface.

Schlumberger Rationale: In some parts of the US the USDW is very deep and this standard may preclude geologic sequestration in these areas.

Response: EPA disagrees with the suggested edit or that the surface casing requirements in the GS rule preclude injection below deep USDWs. The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single or multiple strings of casing and cement. It does not, however, specify how cementing must 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. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24037 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule: (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages.

Schlumberger Suggested Revision: -

Schlumberger Rationale: We support this language work by Carey et al and crow et al shows that CO2 can move above the top of the CO2 reservoir, so cementing to surface will provide the best chance to have maximum zonal isolation

Response: EPA agrees that the requirement for long-string casing of Class VI wells at §146.86(b) will offer the best protection against fluid movement behind the casing, between formations, and above the injection zone and will ensure competency of Class VI wells and protect USDWs from endangerment. The buoyant nature of CO2 dictates deep well construction procedures that address movement of fluid behind the casing and provide necessary barriers to CO2 leakage outside of theinjection zone. In developing the construction requirements for Class VI wells, EPA reviewed the work cited by Carey et al. (2007) and Crow et al. (2008). EPA agrees that they offer important justification for the establishment of tailored requirements.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24971 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule: (viii) Type or grade of cement; and

Schlumberger Suggested Revision: (viii) Type or grade of cement; and additives

Schlumberger Rationale: -

Response: EPA agrees with the suggestion that §146.86(b)(1)(viii) be revised to also address cement additives. In the final GS rule, the subparagraph reads as follows: "Type or grade of cement and
cement additives."

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23237
Comment: Cementing of the long-string casing to surface may not be desirable in all situations; an annulus that can be monitored may be desirable. The long-string casing should be cemented to at least above the upper confining zone. Requiring

Response: EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23288
Comment: 146.86(b)3 Cementing of the long-string casing to surface may not be desirablein all situations; an annulus that can be monitored may be desirable. The longstring casing should be cemented to at least above the upper confining zone.

Response: The final GS rule at §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 adds that, under §146.86(b)(4), the Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator candemonstrate by using logs that the cement does not allow fluid movement behind the wellbore.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Kurt Waltzer Letter ID: 0250 Commenter Organization: Clean Air Task Force Comment ID: 22315
Comment: Cementing requirements for casings

§146.86(b)(3) requires the long string casing to be cemented by circulating cement to surface in one or more stages. It has come to our attention that may be hard to accomplish in some cases, such as very deep wells. We have also been alerted to disadvantages of this approach with regard to the weight of the cement column and its relation to well integrity. We urge EPA to fully consider the advantages and disadvantages of this approach. At a minimum however, the long string casing should be cemented to at least above the confining layer (caprock).

Response: Section 146.86(b)(3) requires that the long-string casing extend to the injection zone and be cemented by circulating cement to the surface in one or more stages. It does not, however, specify how cementing would be accomplished, and gives flexibility to the owner or operator to propose alternate methods to provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment, subject to the approval of the Director. EPA notes that there are many potential ways to meet the requirement in deep wells, such as the use of staged cementing. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA adds that cementing of deep wells has been performed successfully in the past, for example, by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing requirements for long-string casing as Class VI wells, are up to 12,000 feet deep (EPA, 2001).

EPA also received comments from stakeholders representing states, a water association, and industry supporting this provision, saying that it provides, at a reasonable cost, corrosion protection of the casing; prevents undesirable migration of fluids behind the casing; provides support to the casing; and provides multiple barriers against endangerment of USDWs.

EPA stresses that protection of USDWs is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, then the activity will not be allowed under UIC requirements or the SDWA.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements.Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24901 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (viii) Type or grade of cement; and (ix) Quantity, chemical composition, and temperature of the carbon dioxide

stream.

GWPC Recommendations: (viii) Type or grade of cement and additives; and (ix) Quantity, chemical composition, and temperature of the carbon dioxide

stream.

Rationale: Insert "and additives" in (viii)

Response: EPA agrees with the suggestion that §146.86(b)(1)(viii) be revised to also address cement additives. In the final GS rule, the subparagraph reads as follows: "Type or grade of cement and
cement additives."

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24903 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages.

GWPC Recommendations: (3) At least one long string casing, using a sufficient number of centralizers, which at a minimum, would create a cement bond through the confining zone, and which must extend to the injection zone and must be isolated by placing cement and/or other isolation technologies as necessary to provide adequate isolation of the injection zone and provide for protection of

USDWs.

Rationale: Cementing to surface is not necessary to protect USDWS, and may have negative consequences, as follows. Cement to surface would eliminate the ability to monitor pressures in this annulus and would limit flexibility of remedial options. As revised, the proposal would allow for application anddevelopment of alternative technologies. See API RP90 for description of riskbased approach for managing situations involving annular casing pressure. Industry experience with CO2 EOR under the class II program demonstrates the effectiveness of existing cementing procedures.

Response: EPA does not believe that the cementing requirements at §146.86 would preventmonitoring, operation and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24904 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)

EPA Proposal: (4) Circulation of cement may be accomplished by staging. The Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the cement does not allow fluid movement behind
the well bore.

GWPC Recommendations: Delete

Rationale: Same as above

Response: EPA disagrees that the requirement should be deleted. Section 146.86(b)(4) of the final rule allows alternate methods of staging the cement, at the Director's discretion, provided the owner or operator can demonstrate using logs that the cement does not allow fluid movement behind the
wellbore.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Steven Chester Letter ID: 0264 Commenter Organization: Michigan Department of Environmental Quality (MDEQ) Comment ID:

22837 Other EPA Comment Codes and Descriptions: 3822 2.3.1.1 Depth of surface casing (seeking comment)
Comment: EPA (III. A. 3.) proposes a surface casing and long-string casing for a GS well.

- Staff believes an intermediate casing string should be mandated for those areas where such casing is appropriate; for example, where high-pressure gas is known or suspected to exist between the surface casing and the sequestration interval. Such casings should be required to be cemented to

surface.Response: EPA disagrees that specific requirements for intermediate casing strings should be included for all Class VI wells. The rule allows for more than one long-string casing to the injection zone in §146.86(b)(3), in essence permitting intermediate casings.

EPA acknowledges that circumstances such as the presence of high-pressure gas could dictate the use of more than one long-string casing and in this case, each would be required to be cemented from the bottom of the hole to the surface resulting in multiple barriers of cement and casing between formations above the injection zone and the fluids being injected. With their permit applications, owners or operators must submit well construction procedures, as specified in §146.82 (a)(12), that demonstrate that the well, as constructed, will prevent unacceptable fluid movement, as specified in §146.86(a). The Director will evaluate the procedures in the context of other data about the site and may require intermediate casing if it is warranted to protect USDWs from endangerment.

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.

Commenter Name: Donn Miller Letter ID: 0270 Commenter Organization: State of Oregon, Water Resources Department Comment ID: 22886
Comment: 146.86 Injection Well Construction Requirements.

(b)(3) This rule indicates that the wells can be grouted with cement in one or more stages. The problem with cementing in stages is that it is possible to have cold joints that may allow the movement of water or fluids within the annular space. We would prefer that the grout be placed in one continuous operation without a significant interruption. Significant interruption means that the grout should not be allowed to set up to a point that a cold joint would be created when continuing to place grout after an interruption. We suggest that the interruption should not be more than 72 hours if Portland Cement is used, 48 hours if High Early Strength Type III Portland Cement is used or 6 hours if High-Alumina Cement is used. Other interruption times would vary depending on the final set time of the proposed grout.

We also suggest that there be a requirement that the continuous cementing take a minimum amount of grout to complete the seal . For example, the rules should require that a minimum of 120% to 130% of the estimated volume of sealing material be used when sealing. Although this wouldn't guarantee an adequate seal, the chances of a sufficient seal would greater with the appropriate amount of grout. Too little grout would raise a red flag.

Response: EPA believes that staged cementing of long-string casing cement is acceptable with very long casing lengths where one continuous cementing cannot be performed. EPA agrees that the period between grouting jobs should be minimized, although that period, known in the industry as "waiting for cement," is dependent on the time that it takes for the grout in any one stage to set up and cure. As soon as the grout is finished in one stage the staging equipment is moved and new grout is poured.EPA adds that the specifics the commenter mentions should be addressed on an individual project basis. With their permit applications, operators must submit well construction procedures, as specified in §146.82 (a)(12), that demonstrate that the well, as constructed, will prevent unacceptable fluid movement; allow the use of appropriate testing devices and workover tools; and allow continuous monitoring of the annulus space between the injection tubing and long-string casing, as specified in §146.86(a). The Director will evaluate the procedures in the context of other data about the site. 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.

Commenter Name: John McManus Letter ID: 0294 Commenter Organization: American Electric Power Comment ID: 25315 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: 7. Well construction

EPA’s proposed §146.86(b)(3) would require the long string casing to be cemented by circulating cement to surface in one or more stages. Yet that may be hard to accomplish in some cases, such as very deep wells. There are also potential disadvantages of this approach with regard to the weight of the cement column and its relation to well integrity. Sealing this annulus also eliminates an approach for monitoring the integrity of the cement in that critical interval through the primary confining interval and above. We recommend that EPA not make this a mandatory requirement. The requirement should also recognize that there may be other technologies that could be as effective as cement and centralizers, which may not be feasible in some applications; furthermore, current research and development efforts are likely to yield additional technologies the use of which should not be foreclosed. Accordingly, we recommend the following language for §146.86(b)(3):

"(3) At least one long string casing, using a sufficient number of centralizers, which at a minimum: must be sealed from within the injection zone upward through the overlying confining zone, and must provide adequate isolation of the injection zone and other intervals as necessary for protection of USDWs using cement and/or other isolation techniques. The Director may approve the use of packers or alternative isolation techniques, provided these are demonstrated to be equivalent to cement or more effective to provide adequate isolation and to protect USDWs."

Response: EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website athttp://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Section 146.86(b)(3) requires that the long-string casing extend to the injection zone and be cemented by circulating cement to the surface in one or more stages. It does not, however, specify how cementing should be accomplished, and gives flexibility to the owner or operator to propose alternate methods to provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment, subject to the approval of the Director. EPA notes that there are many potential ways to meet the requirement in deep wells, such as the use of staged cementing.

EPA also received comments from stakeholders representing states, a water association, and industry supporting this provision, saying that it provides, at a reasonable cost, corrosion protection of the casing; prevents undesirable migration of fluids behind the casing; provides support to the casing; and provides multiple barriers against endangerment of USDWs.

EPA stresses that protection of USDWs is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, then the activity will not be allowed under UIC requirements or the SDWA.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Michele Schoepper Letter ID: 0503 Commenter Organization: American Petroleum Institute Comment ID: 21177
Comment: The Class II EOR Wells constructed for these projects and operating practices have an excellent record of mechanical integrity testing to protect the USDW. Some of the proposed requirements such as cementing a long stream casing to the surface are not only unnecessarily burdensome, but might also interfere with operations and could introduce unintended risks.

Response: EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001).

EPA recognizes that the GS rule includes requirements (e.g., cementing the entire length of the longstring casing) that are not standard practice in the oil and natural gas industry, but believes that there are significant operational differences between ER and GS. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will 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. Inaddition, CO2 in the presence of water may be corrosive to well materials. For these reasons, 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.

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.

Commenter Name: Brian Williams Letter ID: 0507 Commenter Organization: BP Alternative Energy Comment ID: 21165
Comment: Then on the point of cements across long string casing. The EPA does not agree with the requirement for a long string from the injection interval to the surface, nor with cementing across the entire distance. Allowance should be made for a liner to be set across the injection interval and the previous string set
above that zone.

The cement should cover the uppermost caprock in the area of review by a margin by about 500 feet, not to the surface. The ultimate decision for each project should rest with the director since each is unique and geological intervals and injection zone, and of the position relative to the USDW.

Any expectations of cement at the injection interval should permit the use of external casing packers in conjunction with the cementing requirements.

Response: The final GS rule at §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 adds that, under §146.86(b)(4), the Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the cement does not allow fluid movement behind the wellbore.

The construction requirements at §146.86 offer flexibility to the owner or operator to propose well construction procedures that are appropriate to the site-specific conditions of the project. With their permit applications, operators must submit well construction procedures, as specified at §146.82(a)(12), that demonstrate that the well as constructed will prevent unacceptable fluid movement; allow the use of appropriate testing devices and workover tools; and allow continuous monitoring of the annulus space between the injection tubing and long-string casing, as specified at §146.86(a). The Director will evaluate the proposed well construction procedures in the context of other data about the site. EPA has evaluated the cementing requirements for other well classes and believes that flexibility can be afforded while ensuring that USDWs are protected.

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.Commenter Name: Scott Anderson Letter ID: 0520 Commenter Organization: Environmental Defense Fund Comment ID: 21424
Comment: to sites that are below the lowest USDW. And we would also urge the EPA to give serious consideration to modifying the requirement for cementing the long string casing from top to bottom. We will finish making up our mind about those issues

Response: EPA believes that the requirement for long-string casing of Class VI wells at §146.86(b) will offer the best protection against fluid movement behind the casing, between formations, and above the injection zone and will ensure competency of Class VI wells and protect USDWs from endangerment. The buoyant nature of CO2 dictates deep well construction procedures that address movement of fluid behind the casing and provide necessary barriers to CO2 leakage outside of the injection zone. EPA believes that the requirement provides, at a reasonable cost, corrosion protection of the casing; prevents undesirable migration of fluids behind the casing; provides support to the casing; and provides multiple barriers against endangerment of USDWs.

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 stresses that protection of USDWs is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, then the activity will not be allowed under UIC requirements or the SDWA.

Commenter Name: Steve Crookshank Letter ID: 0523 Commenter Organization: American Petroleum Institute (API) Comment ID: 21360
Comment: Class II EOR wells constructed for these projects and their operating practices have an excellent record of mechanical integrity and protecting USDW's.

Some of the proposed requirements such as cementing the long string casing to surface are not only unnecessarily burdensome, but might also interfere with operations and could introduce unintended risks.

Response: EPA does not believe that the cementing requirements at §146.86 would prevent monitoring, operation and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm

EPA recognizes that the oil and gas industry has decades of experience injecting CO2 and has demonstrated the effectiveness of existing cementing materials and procedures. EPA also believes that GS is sufficiently different from Class II ER operations to warrant the tailored construction requirements for Class VI wells at §146.86. For example, the volume of CO2 anticipated to beinjected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will 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. Therefore, Class VI GS reservoir pressures will increase during the injection phase of the GS project.

Commenter Name: Doug Louis Letter ID: 0530 Commenter Organization: Kansas Corporation Commission Comment ID: 21343
Comment: On proposed injection well construction requirements. The proposed rule requires the long string casing to be cemented in place along its entire length. In a significant area of Kansas, cement cannot be circulated to surface in the bore hole casing annulus in the primary cementing job. To accomplish a continuous cemented interval would involve numerous pipe perforations and cement squeezing operations. This additional remedial work sacrifices mechanical integrity of the pipe for a marginal possibility of additional isolation of the injection zone.

Considering these unique conditions and associated risk, Kansas regulations prescribed an interval of five hundred feet of cemented interval above the injection zone. KCC staff believes an exotic blend of CO2 resistant cement is not needed considering the proven record of CO2 EOR well construction history.

Response: Section 146.86(b)(3) requires that the long-string casing extend to the injection zone and be cemented by circulating cement to the surface in one or more stages. It does not, however, specify how cementing would be accomplished, and gives flexibility to the owner or operator to propose alternate methods to provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment, subject to the approval of the Director. EPA notes that there are many potential ways to meet the requirement in deep wells, such as the use of staged cementing. EPA has evaluated the cementing requirements for other well classes and believes that flexibility can be afforded while ensuring that USDWs are protected.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA adds that cementing of deep wells has been performed successfully in the past, for example, by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing requirements for long-string casing as Class VI wells, are up to 12,000 feet deep (EPA, 2001).

EPA stresses that protection of USDWs is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. Any injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, then the activity will not be allowed under UIC requirements or the SDWA.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs areprotective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

Commenter Name: Talib Syed Letter ID: 0537
Comment ID: 21472
Comment: The requirement that you cement a continuous column of cement for the long string casing again, could be a potential problem. For instance, if you got mud in the bore hole, say you know, a ten pounds per gallon mud and you are displacing cement of fourteen pounds per gallon, then you may unintentionally fracture some deep formations behind the well hole and what you have done is you have damaged the integrity of the well hole and your primary objective in every instance is to make sure that the integrity of the well is the most critical
component.

Many times what happens is that we are looking at it from an environmental perspective, we will look at all environmental considerations, but safety, safety becomes you know, a critical component that would trump environmental
considerations. That does not mean that environmental considerations have to be set aside. Look at that too, but safety will always trump environmental considerations, so if you've got unintended fracturing of the formations of big formations, what have you done? In effect, you have lowered the integrity which was your primary objective to begin with because you want to make sure that you have got the integrity of the well hole. So you know, so in some cases yeah go ahead and do it, but do not mandate it in that okay in every instance, you have to have a continuous column of cement. So that ties in with the integrity because always keep in mind, what is -- how can I maintain the integrity of my well hole throughout the life of the project? Because in EOR applications you know, you are talking about maybe ten million, fifty million, hundred million cubic feet per day of injection, but here you are talking about an exponential manifold increase for geosequestration purposes. You are talking about gigatons

etcetera.

Response: EPA believes that current cementing technology can address deep well cement columns or low-pressure bottom-of-hole formations. The oil and gas industry has experience drilling and cementing wells in very deep formations and in formations with low pressures. Less dense, lighter weight cement slurries that include nitrogen foam or lightweight microspheres (Sabins 2002; Kulakofsky et al. 2005) are used to prevent breakdown of the low pressure formation and loss of circulation. Another way to approach low formation pressure conditions is with reverse cementing (pumping the cement into the annulus and returning it through the casing). This method uses gravity to place the cement and bypass lost circulation zones. Reverse cementing can be combined with other methods such as foam cement. Ten successful reverse-cemented wells have been completed in a variety of onshore/offshore environments (Chase 2008).

EPA believes that the construction requirements at §146.86 offer flexibility to the owner or operator to propose well construction procedures that are appropriate to the site-specific conditions of the project. Section 146.86(b)(3) requires that the long-string casing extend to the injection zone and be cemented by circulating cement to the surface in one or more stages. It does not, however, specify how cementing should 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 areprotected 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.

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment)



### Individual Comments

Commenter Name: Leslie Savage Letter ID: 0122 Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24787 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: (i) Depth of setting; (ii) Characteristics of the CO2 stream (chemical content, corrosiveness, temperature, and density); (iii) Injection pressure; (iv) Annular pressure; (v) Injection rate (intermittent or continuous) and volume of the CO2 stream; (vi) Size of casing; and (vii) Tubing tensile, burst, and collapse strengths.

{Repetitive - See application requirements}

Response: EPA acknowledges that some of the information required under §146.86(c)(3) is also required under §146.82(a)(7) as part of the proposed operating requirements. However, EPA notes that the Director needs to consider all of the data required under §146.86(c) in order to properly determine the tubing and packer specifications, and believes this information should be provided together.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22560
Comment: Injection wells should be designed to inject through tubing. Tubing and packer allow for monitoring pressure in the annulus between the tubing and casing to help identify any leaks. Furthermore the tubing can be replaced relatively easily in the case any damage to the tubing is identified or to change the diameter of the tubing.

Response: EPA acknowledges the comment and agrees that the use of tubing and packer in accordance with §146.86(c) will offer the best multiple-barrier protection of USDWs from endangerment. This requirement is retained in the final GS rule. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24177 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(c)(2)

API Comments: (ii) COMPOSITION of the carbon dioxide stream. (chemical content, corrosiveness, temperature, and density);

Rationale: There is no method for measurement of "corrosiveness" of a CO2 stream. The relevant information is the composition, not characteristics, of the CO2 stream. The composition of the CO2 stream is more relevant to the design of a tubing and packer system.

Rule Provision: 146.86(c)(2)

API Comments: (iii) MAXIMUM PROPOSED Injection temperature and pressure; (iv) MAXIMUM PROPOSED Annular pressure; (v) MAXIMUM PROPOSED Injection rate (intermittent or continuous) and volume of the carbon dioxide stream;

Rationale: Technical corrections.

Response: As written, the text at §146.86(c)(3)(ii) accounts for all characteristics of the CO2 that could affect the performance of the tubing and packer, including the chemical content, corrosiveness, temperature, and density. The suggested revision to refer to CO2 "composition" would be less precise. EPA clarifies that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and described. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational information that the Director needs to determine appropriate standards for the tubing and packer.

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 has revised §146.86(c)(3)(iii) and (iv) to reference the maximum proposed injection pressure and maximum proposed annular pressure, respectively. EPA has revised §146.86(c)(3)(v) to read "proposed injection rate (intermittent or continuous), and volume and/or mass of the carbon dioxide stream." EPA believes that reference to the continuous injection rate would be duplicative of the maximum rate. EPA believes that considering the maximum injection and annular pressure would be more protective.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 29258
Comment: Rule Provisions: 146.86(b) EPA Preamble Question: 16. EPA seeks comment on the proposed GS wellrequirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval. EPA Notice
43509.

Regarding packer setting depth, the director should retain discretion for allowing variation from this requirement.

Response: EPA clarifies that the rule does allow some Director's discretion in approving the owners or operators proposed well construction plan. The Director will evaluate the appropriateness of the proposed construction based on site-specific information about the injection project. EPA believes that the use of tubing and packer in accordance with §146.86(c) will offer the best multiple-barrier protection of USDWs from endangerment. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24341
Comment: EPA should retain the requirement for injection through a tubing and packer to facilitate continuous monitoring of a pressurized annulus. Wells designed with tubing and packer effectively provide two barriers, both of which must be breached before injectate could leave the borehole. At the same time, this design permits a proven method of monitoring that would permit detection of a breach in either barrier so that repairs can be made before both barriers fail. And a requirement to maintain positive pressure on the annulus, rather than always maintaining the annulus pressure in excess of the injected fluid pressure in the injection tubing will be sufficient as CO2 is not hazardous waste.

Response: EPA agrees that the use of tubing and packer in accordance with §146.86(c) will offer the best multiple-barrier protection of USDWs from endangerment. This requirement is retained in the final GS rule. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24452 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(c)(2)(ii)

Proposed CCS Group Recommendations: (ii) Characteristics COMPOSITION of the

carbon dioxide stream. (chemical content, corrosiveness, temperature, and density);

Basis for CCS Group Comments: There is no method for measurement of "corrosiveness" of a CO2 stream. The relevant information is the composition, not characteristics, of the CO2 stream. The composition of the CO2 stream is more relevant to the design of a tubing and packer system.Rule Provision: 146.86(c)(2)(iii) - (v)

Proposed CCS Group Recommendations: (iii) MAXIMUM PROPOSED Injection temperature and pressure; (iv) MAXIMUM PROPOSED Annular pressure; (v) MAXIMUM PROPOSED Injection rate (intermittent or continuous) and volume of the carbon dioxide stream;

Basis for CCS Group Comments: Technical corrections.

Response: As written, the text at §146.86(c)(3)(ii) accounts for all characteristics of the CO2 that could affect the performance of the tubing and packer, including the chemical content, corrosiveness, temperature, and density. The suggested revision to refer to CO2 "composition" would be less precise. EPA clarifies that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and described. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational information that the Director needs to determine appropriate standards for the tubing and packer.

EPA has revised §146.86(c)(3)(iii) and (iv) to reference the maximum proposed injection pressure and maximum proposed annular pressure, respectively. EPA has revised §146.86(c)(3)(v) to read "proposed injection rate (intermittent or continuous), and volume and/or mass of the carbon dioxide stream." EPA believes that reference to the continuous injection rate would be duplicative of the maximum rate. EPA believes that considering the maximum injection and annular pressure would be more protective.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24523
Comment: Rule Provisions or Federal Register Cite: 146.86(b) EPA Preamble Question: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval. EPA Notice
43509.

Regarding packer setting depth, the director should retain discretion for allowing variation from this requirement.

Response: EPA clarifies that the rule allows discretion in some areas when UIC Directors evaluate and approve the owners or operators proposed well construction plan. The Director will evaluate the appropriateness of the proposed construction based on site-specific information about the injection project. EPA believes that the use of tubing and packer in accordance with §146.86(c) will offer the best multiple-barrier protection of USDWs from endangerment. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24679 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(c)(2)(ii)

Anadarko Petroleum Corporation (APC) Comments: (ii) Composition of the carbon

dioxide stream. (chemical content, corrosiveness, temperature, and density);

Rationale: There is no method for measurement of "corrosiveness" of a CO2 stream. The relevant information is the composition of the CO2 stream. The composition of the CO2 stream is more relevant to the design of a tubing and packer system.

Response: As written, the text at §146.86(c)(3)(ii) accounts for all characteristics of the CO2 that could affect the performance of the tubing and packer, including the chemical content, corrosiveness, temperature, and density. The suggested revision to refer to CO2 "composition" would be less precise. EPA clarifies that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and described. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational information that the Director needs to determine appropriate standards for the tubing and packer.

The final GS rule at §146.86(c)(1) also requires that tubing materials used in Class VI wells must meet or exceed standards developed by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. EPA believes that this requirement invokes the expertise of these bodies without the added burden of a certification program.

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.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24680 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(c)(2)(iii) - (v)

Anadarko Petroleum Corporation (APC) Comments: (iii) MAXIMUM PROPOSED Injection temperature and pressure; (iv) MAXIMUM PROPOSED Annular pressure; (v) MAXIMUM PROPOSED Injection rate (intermittent or continuous) and volume of the carbon dioxide stream;

Rationale: Technical corrections.

Response: EPA has revised §146.86(c)(3)(iii) and (iv) to reference the maximum proposed injection pressure and maximum proposed annular pressure, respectively. EPA has revised §146.86(c)(3)(v) toread "proposed injection rate (intermittent or continuous), and volume and/or mass of the carbon dioxide stream." EPA believes that reference to the continuous injection rate would be duplicative of the maximum rate. EPA believes that considering the maximum injection and annular pressure would be more protective.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 29318 Other EPA Comment Codes and Descriptions: 3822 2.3.1.1 Depth of surface casing (seeking comment); 3824 2.3.1.2 Cementing of long-string casing (seeking comment)
Comment: Rule Provisions: 146.86(b) EPA Rule Issue: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval. EPA Notice 43509.

Anadarko Petroleum Corporation (APC) Response: Generally the surface casing is set below the lower USDW but it should be recognized that this is not appropriate in all geologic settings. In some areas USDWs can extend much greater depths than would be appropriate for setting of surface casing. Regulations should recognize these situations and allow for other methods of protecting USDWs

APC opposes the requirement for cementing the long string casing back to surface. Cementing requirements should focus on ensuring competent isolation and seal across the confining zone(s). Sealing the annulus between the long string and surface casing could limit an operators ability to monitor for leakage or conduct remedial operations.

Regarding packer setting depth, the director should retain discretion for allowing variation from this requirement.

Response: Section 146.86(b)(3) requires that the long-string casing extend to the injection zone and be cemented by circulating cement to the surface in one or more stages. It 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 does not believe that the cementing requirements at §146.86 would prevent monitoring, operation, and remediation of GS wells. EPA notes that there are many potential ways to meet the requirement in deep wells, such as the use of staged cementing. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA adds that cementing of deep wells has been performed successfully in the past, for example, by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing requirements for long-string casing as Class VI wells, are up to 12,000 feet deep (EPA, 2001) and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation. EPA also received comments from stakeholders representing states, a water association, and industry supporting this provision, saying that it provides, at a reasonable cost, corrosion protection of thecasing; prevents undesirable migration of fluids behind the casing; provides support to the casing; and provides multiple barriers against endangerment of USDWs.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

EPA clarifies that the rule allows discretion in some areas when UIC Directors evaluate and approve the owners or operators proposed well construction plan. The Director will evaluate the appropriateness of the proposed construction based on site-specific information about the injection project. EPA believes that the use of tubing and packer in accordance with §146.86(c) will offer the best multiple-barrier protection of USDWs from endangerment. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23238
Comment: casing should be cemented to at least above the upper confining zone. Requiring the packer be set opposite a cemented interval is appropriate.

Response: EPA agrees that the use of tubing and packer in accordance with §146.86(c) will offer the best multiple-barrier protection of USDWs from endangerment. This requirement is retained in the final GS rule. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24906 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(c)

EPA Proposal: (c) Tubing and packer.

(1) All owner and operators of Class VI wells must inject fluids through tubing with a packer set at a depth opposite a cemented interval at the location approved by the Director.

(2) In order for the Director to determine and specify requirements for tubing and packer, the owner or operator must submit the following information:

(i) Depth of setting; (ii) Characteristics of the carbon dioxide stream (chemical content,corrosiveness, temperature, and density);

GWPC Recommendations: (c) Tubing and packer.

(1) All owner and operators of Class VI wells must inject fluids through tubing with a packer set at a depth opposite a cemented interval at the location approved by the Director.

(2) In order for the Director to determine and specify requirements for tubing and packer, the owner or operator must submit the following information:

(i) Depth of setting; (ii) Composition of the carbon dioxide stream;

Rationale: What does corrosiveness mean? How is it measured?

Cannot measure the corrosiveness of a carbon dioxide stream.

Composition of the cO2 stream is needed to design a tubing and packer system.

The other listed characteristics are not needed.

Response: As written, the text at §146.86(c)(3)(ii) accounts for all characteristics of the CO2 that could affect the performance of the tubing and packer, including the chemical content, corrosiveness, temperature, and density. The suggested revision to refer to CO2 "composition" would be less precise. EPA clarifies that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and described. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational information that the Director needs to determine appropriate standards for the tubing and packer.

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.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24907 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(c)(2)

EPA Proposal: (iii) Injection pressure; (iv) Annular pressure; (v) Injection rate (intermittent or continuous) and volume of the carbon dioxide

stream; (vi) Size of casing; and (vii) Tubing tensile, burst, and collapse strengths.

GWPC Recommendations: (iii) Maximum proposed Injection temperature and pressure; (iv) Maximum proposed Annular pressure;(v) Maximum proposed Injection rate (intermittent or continuous) and volume of the carbon dioxide stream;

Rationale: It is more helpful to know the recommended information.

The GWPC also recommends addition of the term "proposed in (iii), (iv) and (v) as this section relates to an application and not to actual established permit

conditions

Response: EPA has revised §146.86(c)(3)(iii) and (iv) to reference the maximum proposed injection pressure and maximum proposed annular pressure, respectively. EPA has revised §146.86(c)(3)(v) to read "proposed injection rate (intermittent or continuous), and volume and/or mass of the carbon dioxide stream." EPA believes that reference to the continuous injection rate would be duplicative of the maximum rate. EPA believes that considering the maximum injection and annular pressure would be more protective.

Comment Code: 3840 2.3.2 Horizontal well drilling techniques (seeking comment)



### Individual Comments

Commenter Name: Iain Wright Letter ID: 0118 Commenter Organization: BP Alternative Energy Comment ID: 22065
Comment: So firstly, Well Design. At In Salah, 1mmtpa CO2 is being sequestered in a formation that is 6,000ft deep, 60ft thick and has permeability of only 10mD - very similar to many deep saline formations here in the US Mid-west. To do this, we need only three wells, but they have very long horizontal sections in the storage formation - in fact, they are about as long as they are deep. WE RECOMMEND THAT EPA’S REGULATIONS PERMIT GEO-SEQUESTRATION USING

HORIZONTAL

WELLS.

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Carl Carlsson Letter ID: 0131 Commenter Organization: SUEZ Energy Generation NA, LLC Comment ID: 21530
Comment: Horizontal Well Construction SEGNA supports the allowance of horizontal drilling for well construction, provided that the construction and operation requirements are consistent with those applied
to vertical wells.Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

EPA clarifies that horizontal wells will be subject to the same tailored requirements as vertical wells.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141 Commenter Organization: Global Energy, Inc. Comment ID: 23113
Comment: 2.Horizontal well technology is well known and within the expertise of drilling companies today. We strongly support the use of horizontal wells for this application. As noted in the discussion, EPA acknowledges that horizontal wells will provide excellent benefits, particularly with respect to injection volume and capacity of the geology to handle the rate of injection; as well as minimizing the number of surface sites to achieve the desired injection volume

and rate.

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Brianne Metzger Letter ID: 0151 Commenter Organization: Spectra Energy Corp Comment ID: 21851
Comment: J. The Use Of Horizontal Drilling Should Be Allowed And Encouraged.

As the EPA has noted in the Proposed Rule, horizontal drilling is not typical in deep injection wells in the UIC program. However, horizontal wells have been used successfully for GS, such as the In Salah project in Algeria. Spectra supports the use of horizontal drilling, which has many advantages. For example, a horizontal well in a homogenous reservoir allows the operator to open up more porosity and permeability than one can achieve in a vertical well as the operator is capable of extending the length to be many times the horizontal thickness of the reservoir. This allows the operator to produce or inject over a greater length of reservoir at lower wellbore pressures. Whereas, a horizontal well in a heterogeneous reservoir has a greater probability of intersecting higher permeability streaks, fractures or other geologic features that will allow the operator to inject at higher rates, to reduce wellbore pressure or to access more reservoir per well.Importantly, greater reliance on horizontal drilling also improves the safety and containment of the disposal gas (fluid), as well as the economics of a CCS project as fewer wells are required to inject a given volume. Fewer wells equate to fewer penetrations through the containment zone and lowers the likelihood of leaks through the containment zone, either from leaks around the casing or from corrosion/erosion of wellbore tubulars later in the life of the well. As an exploration tool, horizontal drilling increases the ability to reach areas of the reservoir that an operator may not otherwise be able to reach using vertical drilling. As more porosity and permeability are opened up, the pressure differential across the injection face is reduced and therefore the ability to inject a given volume of gas in a single well bore increases as a ratio of the increased reservoir exposed. As well, by keeping the build section in the cap rock, potentials for bore holes to breach the integrity of the storage reservoir are reduced. Under this concept, fewer penetrations of the cap rock result in less potential for a breach to occur.

Horizontal drilling is only one of a number of new technologies that are being developed for better management of a reservoir, whether it be for oil and gas production, gas storage, coal bed methane production or injection for disposal of waste fluids. EPA should support the use of all new technologies which
contribute to better methods of CCS.

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: James Childress Letter ID: 0158 Commenter Organization: Gasification Technologies Council (GTC) Comment ID: 23782
Comment: EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the applicability of well construction requirements discussed in this proposal. EPA Notice 80.

Horizontal wells should be permitted for injection of CO2. The use of horizontal wells may minimize the number of wells required for injection. A reduced number of wells will reduce both cost and may also reduce potential leakage paths.

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.Commenter Name: Michael J. Miller Letter ID: 0168 Commenter Organization: Electric Power Research Institute (EPRI) Comment ID: 22503
Comment: Preamble, page 43509: "EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the applicability of well construction requirements discussed in this proposal."

EPRI COMMENT #9: We agree with the EPA arguments for this technology and, therefore, believe the merits of horizontal injection wells are correctly stated. In addition, the rule provides flexibility and will encourage GS project development, especially in lower permeability formations needing additional injectivity.

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24233
Comment: Rule Provisions: 146.86 EPA Preamble Question: 18. EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the applicability of well construction requirements discussed in this proposal. EPA Notice 43509.

API Response: Drilling of directional and horizontal wells is an established technology that can significantly reduce surface impacts of a GS project and improve the injection rate of a well. The CO2 injection wells at In Salah, Sleipner, and many in Texas are horizontal or have horizontal sections.

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: James Rower Letter ID: 0173 Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23492 Other EPA Comment Codes and Descriptions: 1250 1.1.1.4 Flexibility is needed (performancebased standards)
Comment: This logic also applies to argue against a prohibition on any type of welldrilling, whether horizontal, vertical, or angled. Id. at 43509. There will likely be a need to maximize capacity for CO2 GS, and it would be premature at this point to impose a blanket prohibition on any type of well drilling without knowing whether that drilling could be done in a manner that is protective of

USDWs.

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Frederick R. Eames Letter ID: 0178 Commenter Organization: CCS Alliance Comment ID: 23865
Comment: Horizontal well construction has proven beneficial in other applications, such as EOR operations, and therefore should be an available option for Class VI wells. The CCS Alliance also supports EPA's proposal to provide Directors the

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Bradley J. Field Letter ID: 0186 Commenter Organization: New York State Dept. of Environmental Conservation
Div. of Mineral Resources Comment ID:

25188
Comment: Q. EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the applicability of well construction requirements discussed in this proposal.

NYSDEC-DMN Response: NYSDEC-DMN believes the decision to use vertical, directional or horizontal wells should be left up to the operator. Horizontal
wells should not be mandated.

Response: In the final rule, EPA allows the use of but does not mandate horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., tomeet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Daniel Plath Letter ID: 0188 Commenter Organization: NiSource, Inc. Comment ID: 25235 Other EPA Comment Codes and Descriptions: 4120 2.4.1.2 Allowing hydraulic fracturing during GS (seeking comment)
Comment: 2. Horizontal Well Construction and Injection Parameter Limitations (73 Fed. Reg. at 43509 and 43510)

The EPA is inclined to permit hydraulic fracturing (frac jobs) and horizontal wells and asks for comments on permitting these technologies. NiSource strongly believes they should be permitted in addition to similar new technologies that will be developed sometime in the future.

Columbia has successfully performed thousands of fracs and refracs in addition to drilling numerous horizontal and other non-vertical types of wells. One of the keys to ensure gas confinement is to have the fewest number of penetrations of the cap rock. Both frac jobs and horizontal wells permit significantly greater injectability from a single well. Our experience is that this type of work can increase injectability by 2 to 8 times or to phrase it differently, only one- eighth to one-half the number of wells would be required to match the equivalent performance of vertical wells or non-stimulated wells.

Whatever technologies that can be employed, whether existing or new, to reduce the number of penetrations are valuable from a surface environmental impact, landowner acceptance, and cost management perspective and should be allowed by this regulation.

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

The final rule allows the use of hydraulic fracturing for purposes of Class VI injection, where approved by the Director. Hydraulic fracturing is one of several stimulation technologies available to improve wellbore and formation injectivity.

EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director and that §146.88(a) permits injection pressure to exceed 90 percent of the fracture pressure only during well stimulation. Owners or operators must submit a proposed stimulation program as part of the permit application under §146.82(a)(9); the plan must demonstrate that any stimulation activities will not compromise the integrity of the confining zone. The Director will evaluate the owner or operator's proposed stimulation plan in the context of all information about the site, and the owner or operator must perform stimulation only as approved.The final rule at §146.91(d)(2) also requires that the owner or operator notify the Director 30 days before performing stimulation during the operational phase of a GS project; this will provide an additional opportunity for the Director to review the owner or operator's plans for stimulation and add other requirements as needed. EPA clarifies that UIC regulations prohibit fracturing of the confining zone at any time during injection or stimulation.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24525
Comment: Rule Provisions or Federal Register Cite: 146.86 EPA Preamble Question: 18. EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the applicability of well construction requirements discussed in this proposal. EPA Notice 43509.

CSC Response: Drilling of directional and horizontal wells is an established technology that can significantly reduce surface impacts of a GS project and improve the injection rate of a well. CO2 injection wells at In Salah, Sleipner, and in many Texas locations are horizontal or have horizontal sections.

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24588
Comment: Rule Provisions: 146.86 EPA Rule Issue: 18. EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the applicability of well construction requirements discussed in this proposal. EPA Notice 43509.

Anadarko Petroleum Corporation (APC) Response: Drilling of directional and horizontal wells is a well established technology that can significantly reduce surface impacts of a GS project as well as improve injection rate of a well. Horizontal wells are currently being utilized in EOR operations and CO2 storage operations successfully.

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.Commenter Name: Richard Guinn Letter ID: 0210 Commenter Organization: Eastman Chemical Company Comment ID: 22732
Comment: EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the applicability of well construction requirements discussed in this proposal. EPA Notice 80.

Horizontal wells should be permitted for injection of CO2. The use of horizontal wells may minimize the number of wells required for injection. A reduced number of wells will reduce both cost and may also reduce potential leakage paths.

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Tiffany Rau Letter ID: 0224 Commenter Organization: Hydrogen Energy International Comment ID: 21683
Comment: (ii) Horizontal Wells Should Be Approved for Geologic Sequestration

HEI agrees with EPA’s discussion regarding the usefulness and benefits of constructing horizontal wells in geologic sequestration projects. It is evident that EPA has done a good amount of research in this area and is well informed on this topic. HEI has direct experience with horizontal wells used in connection with geologic sequestration. At In Salah, 1mmtpa CO2 is being sequestered in a formation that is 6,000ft deep, 60ft thick and has permeability of only 10mD. These characteristics are very similar to many deep saline formations in the United States. To do this, requires only three wells, but the wells have very long horizontal sections in the storage formation. In fact, each well is about as long as it is deep. Horizontal wells provide a means of achieving high performance completions that optimize/improve injectivity. Additionally, horizontal wells can reduce the risk of leakage because their use limits the number of penetrations through the caprock. There are other options to optimize

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Brian Williams Letter ID: 0225Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21733
Comment: (ii) Horizontal Wells Should Be Approved for Geologic Sequestration

BP agrees with EPA’s discussion regarding the usefulness and benefits of constructing horizontal wells in geologic sequestration projects. It is evident that EPA has done a good amount of research in this area and is well informed on this topic. BP has direct experience with horizontal wells used in connection with geologic sequestration. At In Salah, 1mmtpa CO2 is being sequestered in a formation that is 6,000ft deep, 60ft thick and has permeability of only 10mD. These characteristics are very similar to many deep saline formations in the United States. To do this, requires only three wells, but the wells have very long horizontal sections in the storage formation. In fact, each well is about as long as it is deep. Horizontal wells provide a means of achieving high performance completions that optimize/improve injectivity. Additionally, horizontal wells can reduce the risk of leakage because their use limits the number of penetrations through the caprock. There are other options

Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24000
Comment: 1. Schlumberger supports the idea that horizontal wells may be used for injection for geologic carbon sequestration. Horizontal CO2 injection wells have been successfully and safely used for CO2 injection at the Weyburn project in Saskatchewan, Canada. We feel that there will be
sites with conditions that will make the use of horizontal wells

necessary.

Response: In this final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23240
Comment: 18. EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the applicability of well construction requirements discussed inthis proposal. EPA Notice 43509.

Horizontal wells should be allowed. The drilling of these wells has become common in certain basins. Their use would maximize injection while minimizing the surface footprint and injection pressure. Well construction requirements should be similar to vertical wells i.e., the vertical portion of the well should be cemented to above the upper confining zone.

Response: In this final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Walter L. Baker Letter ID: 0253 Commenter Organization: Utah Division of Water Quality Comment ID: 22351
Comment: WELL DRILLING TECHNIQUES

Given the success of horizontal drilling techniques in facilitating geologic sequestration of CO2 in the In Salah project in Algeria, we strongly support allowing innovative drilling techniques in CCGS projects thereby allowing the development of these projects in geologic settings that otherwise might not be amenable to CCGS such as in formations with limited permeability.

Response: In this final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Letter ID: 0263 Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22804
Comment: III A. 3 Proposed Injection Well Construction Requirements

S. EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the applicability of well construction requirements discussed in this proposal.

IOGCC Response: With Director discretion horizontal well drilling techniques maybe appropriate for GS application.

Response: In this final rule, EPA allows the use of horizontal wells at GS projects. In the proposedrule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment. EPA adds that all proposed construction, including the use of horizontal wells, must be approved by the Director.

Commenter Name: Iain Wright Letter ID: 0508 Commenter Organization: BP Alternative Energy Comment ID: 21181
Comment: So first, the well design. At In Salah a million tons a year of CO2 is being sequestered in the formation that's 6,000 feet deep, it's 60 feet thick, and it has a permeability of only 10 milidarcies very similar to many deep saline formations right here in the U.S. Midwest.

To do this we need only three wells, but they have to be very long horizontal sections in the storage formation. In fact, they are about as long as they are deep. So we recommend that EPA's regulations permit geo-sequestration using
horizontal wells.

Response: In this final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Commenter Name: Talib Syed Letter ID: 0537
Comment ID: 21473
Comment: The next point I would like to make is we have not considered horizontal wells. In the rules that were, the proposed rules I have not seen anything on, as far as horizontal wells. Are horizontal wells going to be used for completion of geosequestration wells and how does that play into the matrix?

Response: In this final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, electric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously supported the concept and provided many reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment.

Comment Code: 3860 2.3.3 Well component degradation

### Individual Comments

Commenter Name: Leslie Savage Letter ID: 0122 Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24782 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: (b) Casing and Cementing of Class VI Wells.

(1) Casing and cement or other materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the
OPERATING life of the WELL geologic sequestration project . All well materials must be compatible with fluids with which the materials may be expected to come into contact and meet or exceed standards developed for such materials by the API, ASTM International, or comparable standards acceptable to

the Director. The casing and cementing program must be designed to prevent
the movement of fluids into or between USDWs. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information:

{The threat to the integrity of the casing and cement and other materials is greatest during injection, and quickly decreases as the pressure dissipates after cessation of injection. }

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 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.

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0127 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 23055
Comment: 14. Any existing wells penetrating the injection zone is subject to failure.

15. EPA has approved Sequestration wells as Class I and/or Class II wells, even though adequate materials are not available.

Response: EPA acknowledges that any injection well can potentially fail. It is for this reason that the GS rule contains multiple, tailored requirements for the siting, operation, MIT, monitoring, reporting, plugging, and post-injection site care and site closure of Class VI wells to protect USDWs from endangerment.EPA believes that adequate materials that are appropriate for CO2 injection for GS exist. EPA believes that the requirement at §146.86(b)(1) that materials must meet or exceed standards developed by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director invokes the expertise of these bodies without the added burden of a certification program. 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 clarifies that all wells used for CO2 injection for the purpose of GS must meet requirements in the final GS rule.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24171 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(1)

API Comments: (1) Casing and cement or other materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the operating life of the geologic sequestration projectWELL. All well

materials must be compatible SUITABLE FOR USE with the fluids with which the materials may be expected to come into contact and meet or exceed TEST standards OR PRACTICES developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. The casing and cementing program must be designed to prevent the movement of fluids into or between USDWs. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information:

Rationale: The life of a geologic sequestration project could be different than the life of the well. Class VI well design should be based on the life of the
well.

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.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24173 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(1)API Comments: (vi) Down-hole temperatures AND PRESSURES; (viii) Type or grade of cement AND ADDITIVES; and

Rationale: Technical clarification.

Response: EPA agrees with the suggestion that §146.86(b)(1)(viii) be revised to also address cement additives. In the final GS rule, the subparagraph reads as follows: "Type or grade of cement and
cement additives."

EPA clarifies that information on down-hole pressures is required at §146.86(b)(1)(ii).

Commenter Name: Bradley J. Field Letter ID: 0186 Commenter Organization: New York State Dept. of Environmental Conservation
Div. of Mineral Resources Comment ID:

25189
Comment: R. EPA seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion resistant casing.

NYSDEC-DMN Response: With regard to degradation-resistant well construction materials, the EPA rule should not be overly prescriptive but instead set performance standards that would allow case-by-case basis evaluation of casing and cementing materials necessary to meet the standards.

Response: EPA clarifies that acid-resistant cement is not specifically required in a Class VI injection well. Rather, as stated in §146.86(b)(1), casings and cement used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards listed in the rule and be compatible with fluids with which the materials may be expected to come into contact. Therefore, some well materials may need to be acid-resistant and some may not if they do not come in contact with the CO2 stream or other corrosive fluids and if approved by the Director.

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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24444 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(1)

Proposed CCS Group Recommendations: (1) Casing and cement or other materials
used in the construction of each Class VI well must have sufficient structural strength and be designed for the operating life of the geologic sequestration projectWELL. All well materials must be compatible SUITABLE FOR USE with the fluids with which the materials may be expected to come into contact and meet or exceed TEST standards OR PRACTICES developed for such materials by theAmerican Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. The casing and cementing program must be designed to prevent the movement of fluids into or between USDWs. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information:

Basis for CCS Group Comments: The life of a geologic sequestration project could be different than the life of the well. Class VI well design should be based on
the life of the well.

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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24446 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(1)(vi)

Proposed CCS Group Recommendations: (vi) Down-hole temperatures AND PRESSURES;

Basis for CCS Group Comments: Technical clarification

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

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24671 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(1)

Anadarko Petroleum Corporation (APC) Comments: (1) Casing and cement or other
materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the operating life of the geologic sequestration projectWELL. All well materials must be compatible SUITABLE FOR USE with the fluids with which the materials may be expected to come into contact and meet or exceed TEST standards OR PRACTICES developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. The casing and cementing program must bedesigned to prevent the movement of fluids into or between USDWs. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information:

Rationale: The life of a geologic sequestration project could be different than the life of the well. Class VI well design should be based on the life of the
well.

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.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24673 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(1)(vi)

Anadarko Petroleum Corporation (APC) Comments: (vi) Down-hole temperatures AND PRESSURES;

Rationale: Technical clarification

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

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24674 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(1)(viii)

Anadarko Petroleum Corporation (APC) Comments: (viii) Type or grade of cement AND ADDITIVES; and

Rationale: Technical clarification.

Response: EPA agrees with the suggestion that §146.86(b)(1)(viii) be revised to also address cement additives. In the final GS rule, the subparagraph reads as follows: "Type or grade of cement and
cement additives."Commenter Name: Robert E. Carter Jr. Letter ID: 0236 Commenter Organization: Indiana Department of Natural Resources (IDNR) Comment ID: 29217
Comment: States like Indiana with a proven track record of effectively managing similar programs have indeed demonstrated an ability to adapt to evolving technologies and we believe do possess the capability to effectively address long-termstorage issues. In fact, as indicated earlier in our comments, many of the longterm issues associated with CCGS operations will be outside the purview of the UIC Program and will need to be addressed by states as they enact appropriate CCGS legislation. EPA should consider implementing rules which afford states with the greatest flexibility to select regulatory options that are best suited to their specific needs and conditions. Specific examples of requirements that may be too prescriptive include:

2. Prescriptive requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion resistant casing.

Response: EPA disagrees that the well construction standards for Class VI wells are too stringent. Instead, the construction requirements at §146.86 provide an appropriate level of protection from endangerment to USDWs that is based upon the existing UIC framework for deep wells. The new tailored approach was designed to address the general risks deep injection may pose to USDWs and was tailored specifically to address the unique nature of CO2 GS (i.e., 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 also believes that the regulations allow appropriate flexibility to the Director to evaluate theappropriateness of the owner or operator's proposed well construction procedures based on sitespecific information about the injection project, including injection pressures, injection and confining zone lithology, and information about the carbon dioxide stream as provided in §146.86(b)(1). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility regarding appropriate materials for 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).

Commenter Name: Mark E. Fesmire Letter ID: 0237 Commenter Organization: New Mexico Oil Conservation Division (NMOCD) Comment ID: 23210

Comment: C. The proposed regulations do not seem to adequately address the detrimental thermal effects on well integrity caused by near well bore phase changes. It is highly probably that pressure losses thru perforations of injected supercritical fluid during early phases of a sequestration project in a depleted oil or gas reservoir (where the pressure is below the supercritical pressure) will result in phase changes at the perforations that will have a thermal effect onmechanical integrity of the casing cement system.

Response: Injection depth will be a vital consideration if formations designated to receive supercritical CO2 are of such low pressure that supercritical CO2 reverts to its gas phase upon entry. This could result in thermal shock if expansion of gaseous CO2 causes a drop in temperature (the Joule-Thomson effect). Thermal shock is a common cause of cracking in many types of pressure equipment, and repeated exposure to such stresses could compromise the integrity of the injection well's tubular components. EPA believes that the continuous pressure monitoring required at §146.85, which can detect early effects of thermal shock, along with the construction requirements at §146.86 and the testing and monitoring requirements at §146.90, provide a multiple barrier approach to protecting USDWs from endangerment. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidances on the construction of Class VI wells and testing and monitoring for GS projects. These guidances will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Philip Papadeas Letter ID: 0238 Commenter Organization: Sandia Technologies, LLC Comment ID: 23351 Other EPA Comment Codes and Descriptions: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83)
Comment: §146.82 (h) (i, j) Re: Compatibility testing should be performed from cores and either native or synthesized formation fluid and injectate to determine and demonstrate potential reactivity of the injectate with formations, tubular materials, and other waste or injectate mixtures. This is presently performed for all Class I hazardous wastes, and should be employed as a one-time initial testing program for new well operations and injection constituents, composition and properties.

Response: EPA has revised subpart §146.82 so that the final regulation specifies separate requirements for information to be submitted with the permit application and before well construction is approved (at §146.82(a)) and information to be submitted before operation of the well is authorized (at §146.82(c)).

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23286
Comment: 146.86(b)1(v) How is corrosiveness measured?

Response: EPA clarifies that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and described. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational information that the Director needs to determine appropriate standards for the tubing and packer.

The final GS rule at §146.86(c)(1), also requires that tubing materials used in Class VI wells must meet or exceed standards developed by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. EPA believes that this requirement invokes the expertise of these bodies without the added burden of a certification program.

See the discussion of Class VI well construction requirements in the preamble to the final GS rulefor 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.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23290
Comment: 146.86(c)2(ii) How is corrosiveness measured?

Response: EPA clarifies that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and described. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational information that the Director needs to determine appropriate standards for the tubing and packer.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24898 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (b) Casing and Cementing of Class VI Wells.

(1) Casing and cement or other materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the life of the geologic sequestration project. All well materials must be compatible with fluids with which the materials may be expected to come into contact and meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. The casing and cementing program must be designed to prevent the
movement of fluids into or between USDWs. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information:

GWPC Recommendations: (1) Casing and cement or other materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the life of the operating life of the well. All well materials must be compatible with fluids with which the materials may be expected to come into contact and meet or exceed test standards or practices developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. The casing and cementing program must be designed to prevent the movement of fluids into or between USDWs. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information:

Rationale: Suggest substituting "operating life of the well" for "the life of the geologic sequestration project" in (1) The GWPC determined that geologic sequestration project was a nebulous term that could not be calculated and thus would have no meaning in designing a casing or cementing program.

IMirror the non endangerment standard.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 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.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24899 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(1)

EPA Proposal: (i) Depth to the injection zone; (ii) Injection pressure, external pressure, internal pressure and axial loading; (iii) Hole size; (iv) Size and grade of all casing strings (wall thickness, external diameter, nominal weight, length, joint specification and construction material); (v) Corrosiveness of the carbon dioxide stream, and formation fluids; (vi) Down-hole temperatures; (vii) Lithology of injection and confining zones;

GWPC Recommendations: (i) Depth to the injection zone;

(iii) Hole size; (iv) Size and grade of all casing strings (wall thickness, external diameter, nominal weight, length, joint specification and construction material); (v) Predicted corrosiveness of the combined carbon dioxide stream and formation fluids; (vi) Down-hole temperatures and pressures; (vii) Lithology of injection and confining zones;

Rationale: What is meant by external and internal pressure? Recommend deleting (ii).

Insert "and pressures" in (vi)

Cannot measure the corrosiveness of the CO2 stream because it is not corrosive. Only liquids will yield pH measurements.

Response: EPA disagrees with the suggested edits. The internal and external pressure mentioned in §146.86(b)(1)(ii) refers to pressure on the well casing. Internal pressures could be caused by cement or annular fluids; external pressures could be caused by cementing against the borehole or pressure

head from formations.At §146.86(c)(3)(ii), EPA clarifies that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and described. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational information that the Director needs to determine appropriate standards for the tubing and packer. EPA believes that this subpart accounts for all characteristics of the CO2 that could affect the performance of the tubing and packer, including the chemical content, corrosiveness, temperature, and density.

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.

Commenter Name: Iain Wright Letter ID: 0508 Commenter Organization: BP Alternative Energy Comment ID: 21182 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: At In Salah a few miles up from the three CO2 injectors we have four wells that produce natural gas from exactly the same geological formation. The design of the CO2 injectors is identical to the design of natural gas producers, except that the gas producers have stainless steel tubing, whereas, the CO2 injectors have conventional mild steel or L80 tubing. This is because the gas producers are actually in a more corrosive environment than the CO2 injectors.

So just to emphasize that point, the CO2 sequestration wells permit the, in In Salah, are constructed to a lower specification than the natural gas wells in

the same formation.

So we recommend that the design and construction of geo-sequestration wells should be site-specific and fit for the purpose of preventing endangerment to

USDWs.

Response: EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility regarding appropriate materials for 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). The Director will evaluate the owner or operator's proposed construction procedures, including materials to be used, in the context of information about the well, the CO2 stream, and the site, as specified in §146.86(b)(1). EPA is aware of GS efforts at In Salah and clarifies that the wells in question were not constructed in accordance with US regulations, so the comparison is not necessarily analogous. A paper summarizing EPA's review of In Salah and other large international GS projects is in the rulemaking docket.

Comment Code: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)

### Individual Comments

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22524
Comment: EPA believes Class VI wells and associated reservoirs will be safe, even though corrosion resistant materials are not available. Again EPA says "not to worry" EPA "knows" the Oil and Gas Industry will develop corrosion resistant pipe and cement, when they are needed. Our investigation shows no pipe, packer, rubber seal or cement have been tested resistant to carbonic acid attack for 50 years (maximum test length to date is 12 months!). Thus, when the well or formation fails (leaks), the CO2 phase changes(from liquid to gas). This will result in a massive increase in volume as the CO2 approaches the earth’s surface causing vast destruction. EPA is not authorized by the Safe Drinking Water Act to consider protection of human life from such a disaster. Since the disaster may occur where there is no USDW the Statue provides no-protection for the general public from a release. Thus, at some future time the sequestration system operating at 2215± psia (Moore, et al) can fail due to corrosion (Meyer, 2007) or the carbon dioxide finds its way explosively to the earth’s surface.

Meyer (2007) reports severe corrosion of stainless steel 404 components during injection at an enhanced oil recovery (EOR) using carbon dioxide. Also, Newton and McClay (1977) say "[p]redict[ing] ... corrosivity based on CO2 and water cuts have not always proved accurate." The presence of water insitu to storage reservoirs typically increases the corrosive nature of this CO2. The injected CO2 is buoyant and rises to the bottom of the top confining zone. The confining zone is penetrated by at least one injection well and probably other wells. These wells must have casing, which will corrode quickly unless there is a constant injection of corrosion inhibitor (Thomasville. MS experience).

A review of the Department of Energy, State of Washington and State of New Mexico reports and rules shows none of these Agencies are willing to discuss the types of material appropriate for well completion components. This is true, also, of the IOGCC (2007) report. On the other hand, EPA at 73 FR 43510 suggests using stainless steel 316 fittings, and forgings on the basis of recommendation of Meyer (2007) for surface connections associated with EOR wells injecting dry CO2. We asked Dr. Meyer for clarification regarding the reported corrosion. Dr. Meyer provided reference to two paper demonstrating severe corrosion of carbon steel (Schemp and Roberson, 1975; Newton and. McClay, 1977.

We know the stainless steel components have corrosion problem, Meyer, 2007. Further investigation establishes that only one stainless steel 316 wellhead assembly has ever been made in the U.S. This means EPA already has approved CO2 sequestration wells without SS 316 components. This means existing CO2 injection wells are subject to carbonic acid agression, making the wells current RCRA (RCRA’s §7003) and CERLA (CERCLA §106) imminent hazards. Meyer (2007), also discusses, use of epoxy coated tubing for enhanced oil recovery. THIS PLASTIC COATED TUBING IS PULLED AND INSPECTED YEARLY. Yearly inspection of tubing for 50 years does not appear practical for CO2 sequestration wells! Each time the tubing is pulled, the coating at the threaded joint wears and/or chips, exposing the carbon steel to carbonic acid corrosion. This corrosive attackwill result in rapid exteriorization of the tubing.

The packer presents a particularly difficult design problem. A stainless steel packed body can be manufactured. But, the slip must be hardened carbon steel so they set in the casing wall to compress the elastomer seal. Stainless steel work hardens, but it is not heat treatable. Thus, making stainless steel slips appears highly questionable. Packer elastermers, e.g. Buna-N and Nitrile rubbers, are available, but never tested over long time periods, e.g., 50 years, in the presence of carbonic acid. Schemp, and Roberson, (1975) report "[T]ests showed nonmetallic seals to be susceptible to acid and mechanical damage." Tubingless completions are possible, but this would expose the casing to acid attack. Multiple cemented casing strings can be run. However, steel is known to corrode rapidly in the presence of carbonic acid.

Meyer, J.P. 2007. "Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well Technology" prepared for American Petroleum Institute, p 21.

Moore, J.J. M. Nord and K. Brun, 2007. Novel Concepts for Compression of Large Volumns of Carbon Dioxide, Oil and Gas Journal, June

Newton Jr., L.E., and R.A. McClay, 1977. Corrosion and Operational Problems, CO2 Project, Sacroc Unit, SPE 6391-MS

Schemp, F.W., and G.R Roberson, 1975. Effect of Supercritical Carbon Dioxide (CO2) on Construction Materials, SPE Journal, 15:3, June. Paper 4667-MS..

Response: EPA disagrees that corrosion-resistant materials and cement do not exist. Meyer (2007) lists several types of cements that have been used under corrosive conditions. EPA acknowledges that studies have likely not been performed to prove a 50-year life span for corrosion-resistant materials. However, there are two studies of wells that were exposed to CO2 for approximately 30 years by Carey et al. (2007) and Crow et al. (2008). Although these studies are limited in the number of well material samples and the number of wells examined, the casing and cement sampled indicate fairly good condition (i.e., fairly significant corrosion resistance) of well materials installed three decades ago. The best available corrosion-resistant materials suited for each GS project will be determined by the Director.

EPA clarifies that Grade 316 stainless steel is not a specified material. It is discussed in the preamble to the proposed rule as an example of materials that have been used successfully in similar situations. The determination of the best material to use is left for the Director to approve based upon case-specific information as provided under §146.86(b)(1).

EPA acknowledges that there is limited data on this subject, and believes that providing multiple barriers of protection is the most appropriate approach to protecting USDWs from endangerment. 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.

The Agency plans to, every six years, collect and review project data on early GS projects as well as industry innovations on cementing including the development of CO2-resistant epoxy cements todetermine 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.

Commenter Name: Brian Williams Letter ID: 0116 Commenter Organization: BP Alternative Energy Comment ID: 22050 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: I would like to comment on certain of the incremental requirements in the draft rule, including the preamble, around the design, construction & operation of Class VI wells that we feel are potentially excessive.

WELL CONSTRUCTION

Corrosion resistant materials & cement - Based on industry experience and field studies, corrosion resistant materials should not be mandated for all projects, and the requirement, if there is any, should be made on a site-specific basis. Early field studies (by the CO2 Capture Project) indicate that it is the appropriate placement of cement, and not the type of cement, that delivers isolation & prevents casing corrosion.

Response: EPA agrees that proper cement placement is extremely important to the integrity of a Class VI well. However, even proper cement placement cannot compensate for an improper type ofcement. It is also important that the cement type be appropriately CO2 compatible and corrosionresistant, and suitable to both the CO2 stream and formation fluids. Data from research and the field show that various cement designs are subject to chemical alteration when exposed to CO2 (e.g., Barlet-Gouedard et al., 2006; Kutchko et al., 2007; Carey et al., 2007). 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).

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.

Commenter Name: Brian Williams Letter ID: 0116 Commenter Organization: BP Alternative Energy Comment ID: 22051 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: The choice of casing and cement materials should be selected based on planned well operating life (i.e., decades), not on the ultimate duration of the storage program. The potential for longer term exposure of casing during storage, which might occur after injection has stopped, is mitigated by plugging the static well with corrosion-resistant material, if it is deemed necessary at that time.

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 areanticipated 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.

Commenter Name: Iain Wright Letter ID: 0118 Commenter Organization: BP Alternative Energy Comment ID: 22066 Other EPA Comment Codes and Descriptions: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 146.86)
Comment: At In Salah, a few miles up-dip from the three CO2 injectors, we have four wells that produce natural gas from the same geological formation. The design of the CO2 injectors is identical to the design of the gas producers except that the gas producers have stainless steel tubing, whereas the CO2 injectors have conventional mild steel (L80) tubing. This is because the gas producers are actually in a more corrosive environment than the CO2 injectors. So, just to emphasize that point: the CO2 sequestration wells, permitted at In Salah are constructed to a lower specification than the natural gas wells in the same
formation. WE RECOMMEND THAT THE DESIGN AND CONSTRUCTION OF GEOSEQUESTRATION

WELLS SHOULD BE SITE-SPECIFIC AND FIT FOR THE PURPOSE OF PREVENTING

ENDANGERMENT

OF USDWS.

Response: EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility regarding appropriate materials for 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). The Director will evaluate the owner or operator's proposed construction procedures, including materials to be used, in the context of information about the well, the CO2 stream, and the site, as specified in §146.86(b)(1). EPA is aware of GS efforts at In Salah and clarifies that the wells in question were not constructed in accordance with U.S. regulations, so the comparison is not necessarily analogous. A paper summarizing EPA's review of In Salah and other large international GS projects is in the rulemaking docket.

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0127 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 23053
Comment: B: EPA STATES THE NECESSARY MATERIALS FOR THE COMPLETION OF SEQUESTRATION

INJECTION WELLS ARE NOT CURRENTLY AVAILABLE.

1. CO2 when mixed with water forms carbonic acid.2. Well casing, valves, packer slips and connectors are typically manufactured

from carbon steel.

3. Carbon steel is highly corrosive when in contact with carbonic acid.

4. Stainless steel 404 is attacked by carbonic acid.

5. EPA suggests using stainless steel 316 for well heads on the basis on one Enhanced Oil Recovery injection well.

6. Cameron reports manufacturing only one SS 316 wellhead and Cameron does not
know the fate of the one 316 wellhead.

7. My personal contact with the project consulting engineer for the well used by EPA resulted in no response regarding the corrosion resistance of SS 316.

8. EPA say in the proposed rule, “Not to worry” the Petroleum Industry will develop the need materials. This is the same industry EPA disparages. EPA in the proposed rule requires the completion materials to be corrosion restraint. I wish it was that easy.

Response: EPA disagrees that corrosion-resistant materials and cement do not exist and the research literature describes several types of cements that have been used under corrosive conditions.

EPA clarifies that Grade 316 stainless steel is not a specified material. It is discussed in the preamble to the proposed rule as an example of materials that have been used successfully in similar situations. The determination of the best material to use is left for the Director to approve based upon case-specific information as provided under §146.86(b)(1).

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.

Commenter Name: Emily Rochon Letter ID: 0129 Commenter Organization: Greenpeace International Comment ID: 23072 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: Given the risk of corrosion and leakage, we are strongly supportive of proposal’s language regarding the use of anti- corrosive cements and only allowing anti-corrosive materials for wells. This is an essential requirement to reduce the risks of leaks in the wells which will likely pass through drinking water reservoir and pose the most severe risk to the water supply. Another part

Response: EPA agrees that cement that is compatible with the CO2 and formation fluids will enhance Class VI well integrity. In the interest of USDW protection, the Agency requires that the materials used in Class VI wells must be compatible with fluids with which they may come in contact, as specified in §146.86(b)(1).

EPA adds that the requirements at §146.86(b)(1) state that the materials must meet or exceedstandards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. This requirement invokes the expertise of these bodies and allows the use of technologies that are yet to be developed.

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.

Commenter Name: Robert Bessette Letter ID: 0139 Commenter Organization: Council of Industrial Boiler Owners (CIBO) Comment ID: 23083 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: B. Flexibility in Materials Selection

In the carbon capture and sequestration process, accompanying impurities will likely be incorporated into the carbon dioxide stream and injected in the geologic sequestration zone. As EPA notes, these accompanying particles may have a corrosive effect on the tubing and casing used to contain the carbon dioxide, compromising the safety and security of the sequestration zone. CIBO supports the proposed regulations allowing for variability in setting standards for casing, cementing, and tubing of the Class VI wells. Under the regulations, the Director will determine the standards for these materials on a case-by-case basis, taking into consideration the chemical composition of the carbon dioxide stream.[FN4 Proposed Rule, Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells, 73 Fed. Reg. 43492, 43509-10 (July 25, 2008) (to be codified at 40 C.F.R. §46.86).] CIBO supports this provision is imperative to the safety and security of the carbon capture and sequestration process.

Response: EPA agrees that cement that is compatible with the CO2 and formation fluids willenhance Class VI well integrity. EPA also agrees that developing technology in the field of acidresistant cement will provide the industry with future benefits. In the interest of USDW protection, the Agency requires that the materials used in Class VI wells must be compatible with fluids with which they may come in contact, as specified in §146.86(b)(1).

EPA adds that the requirements at §146.86(b)(1) state that materials must meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. This requirement invokes the expertise of these bodies and allows the use of technologies that are yet to be developed.

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.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141 Commenter Organization: Global Energy, Inc. Comment ID: 23114Comment: 3.We recommend that specifics of the site, as well as fluid and geologic characteristics, dictate the materials used in well construction, particularly whether stainless steel is really appropriate. We suspect Grade 316 stainless may not always be appropriate or necessary especially when considering conversion of EOR wells to GS duty.

Response: EPA clarifies that Grade 316 stainless steel is not a specified material. It is discussed in the preamble to the proposed rule as an example of materials that have been used successfully in similar situations. The determination of the best material to use is left for the Director to approve based upon case-specific information as provided under §146.86(b)(1).

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22601 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: Proposed Rule: 146.86(b)(1)

Comment: NGWA supports this provision

Response: EPA agrees that cement that is compatible with the CO2 and formation fluids willenhance Class VI well integrity. EPA also agrees that developing technology in the field of acidresistant cement will provide the industry with future benefits. In the interest of USDW protection, the Agency requires that the materials used in Class VI wells be compatible with fluids with which they may come in contact, as specified in §146.86(b)(1).

EPA adds that the requirements at §146.86(b)(1) state that materials must meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. This requirement invokes the expertise of these bodies and allows the use of technologies that are yet to be developed.

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.

Commenter Name: Patrick Nugent Letter ID: 0143 Commenter Organization: Texas Pipeline Association (TPA) Comment ID: 23141 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: 8. Imposition of corrosion-resistant materials is too prescriptive.Requirements concerning use of particular materials should be imposed on a caseby-case basis. For example, the regulations should not require that all projects use corrosion-resistant materials, because isolation and corrosion prevention isthe result of the proper placement of cement, rather than the type of cement used. Any requirement related to the use of corrosion-resistant materials should be made on a site-by-site basis. Imposition of inflexible, across-the-board materials requirements would unduly hinder development and use of geologic sequestration technology, given that the use of conventional materials will adequately ensure project integrity in many cases.

9. Casing material requirements are similarly prescriptive. Requirements concerning use of particular casing materials should be based on the planned operating life of the injection program, rather than the life of the storage program. Long-term exposure of the casing materials, during storage, can be dealt with through plugging if necessary.

Response: EPA clarifies that corrosion-resistant cement is not specifically required in a Class VI injection well. Rather, as stated in §146.86(b)(1), casings and cement used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards listed in the rule and be compatible with fluids with which the materials may be expected to come into contact. Therefore, some well materials may need to be acid-resistant and some may not if they do not come in contact with the CO2 stream or other corrosive fluids and if approved by

the Director.

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 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.

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.

Commenter Name: Michael J. Miller Letter ID: 0168 Commenter Organization: Electric Power Research Institute (EPRI) Comment ID: 22498 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment); 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 146.92)
Comment: Preamble, page 43507: "Today’s proposal does not prescribe the specific cements to be used to plug abandoned wells..."

Also, preamble, page 43510: "EPA seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion resistant casing."EPRI COMMENT #5: We question the adequacy of the evidence employed to justify requiring the use of corrosion resistant cements in all cases. The laboratory study performed by Duguid, et al. (2004) cited by EPA exposed portland cement samples to acidified waters in an aggressive flow configuration uncharacteristic of a borehole environment. In contrast, the field study by Crow, et al. (2008) performed on a 30 year old production well is characteristic of a borehole environment. Side-wall cores of the casing, acoustic bond logs and well integrity tests did not show signs of casing corrosion, leakage or cement-bond degradation. While side-wall cores of the cement indicated that CO2-induced cement alteration had occurred, the hydraulic integrity of the cement seal was still highly effective. EPA states that the cement alteration found in the study demonstrates that CO2 migrated up the borehole. We question this conclusion and believe the study is not conclusive on this point. Given that the study was performed on a natural CO2 reservoir, free and dissolved CO2 are expected to be present throughout the stratigraphic column from the top of the reservoir through the confining unit to the surface. Therefore, an alternative hypothesis is that the native CO2 present in the confining unit or caprock adjacent to the
cement seal caused the observed alteration. Evidence that the cement underwent greater alteration at the cement-formation interface adjacent to the caprock compared to the cement-casing interface located further from the caprock helps support this hypothesis. Most importantly, the seal maintained its integrity, exhibiting very low cement matrix, and low interface permeabilities, as determined by laboratory and vertical interference tests in the field, respectively. However, should the EPA eventually adopt a requirement for corrosion-resistant materials, we believe EPA is taking the correct approach by not prescribing the type of corrosion-resistant cements and casing to be used in well completions and abandonments; a number of materials are available and selection of a given material may be driven by site-specific well

characteristics.

Duguid, A., M. Radonjic, R. Bruant, T. Mandecki, G. Scherer, and M. Celia. 2004. The Effect of CO2 Sequestration on Oil Well Cements. Presented at the Greenhouse Gas Technologies Conference (GHGT-7), September 5-9, 2004. Vancouver, Canada.

Crow, W., D.B. Williams., B. Carey, M. Celia, and S. Gasda. 2008. CO2 Capture Project Field Study of A Wellbore from a Natural CO2 Reservoir. Presented at the 7th Annual Conference on Carbon Capture and Sequestration, May 5-8, 2008. Pittsburgh, Pennsylvania.

Response: EPA considered both field and lab studies in developing the requirements for Class VI well construction. The Duguid study referenced by the commenter examined a CO2-saturated brine flux condition that may be found in some injection environments such as a saline aquifer. The Crow study mentioned was a well that produced gaseous CO2 from a natural CO2 deposit. In the studies examined, cement alteration and corrosion was found to occur at differing rates. Factors such as contact with brine, temperature, CO2 flux, and time between cement curing and CO2 exposure may all be relevant. See the discussion of Class VI well construction requirements in the preamble to the
final GS rule for additional information.

EPA clarifies that corrosion-resistant cement is not specifically required in a Class VI injection well.Rather, as stated in §146.86(b)(1), casings and cement used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards listed in the rule and be compatible with fluids with which the materials may be expected to come into contact. Therefore, some well materials may need to be acid-resistant and some may not if they do not come in contact with the CO2 stream or other corrosive fluids and if approved by the Director.

EPA clarifies that the GS rule does not prescribe the specific cements to be used to plug abandoned wells in the AoR because industry standards, such as those developed by API or ASTM International, reflect the current state of the science and the expertise of industrial users on CO2- compatible materials, as specified in §146.92(b). Providing flexibility to choose materials for plugging, provided they are compatible with the injected fluid, is consistent with requirements for other injection well classes and will allow operators to utilize improved well technologies as they become available in the future without a need to amend the regulation.

EPA plans to, every six years, collect and review project data on early GS projects and continue to monitor field and laboratory research 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.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24234 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: Rule Provisions: 146.86, 73 FR 43510 EPA Preamble Question: 19. EPA seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion resistant casing. EPA Notice 43510.

API Response: The well should be looked at as a system such that not each individual component needs to be CO2 resistant as long as the entire system provides an effective barrier under the subsurface conditions. Industry experience with CO2 EOR strongly supports the use of conventional oil field tubing, casing, and cements. Industry experience over the past 35 years has led to the development of corrosion mitigation measures (e.g. plastic or epoxy lined tubing, use of corrosion inhibitors, and proper dehydration of CO2) that provide a high degree of protection and mitigate any corrosive effects of injected CO2.

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced recovery, and that this practice has led to the development of many corrosion mitigation measures that would be appropriate for the design of Class VI wells.

EPA believes that the GS rule provides flexibility: it does not specify materials to be used; rather, it provides owners or operators with the flexibility to choose, as long as the materials used in Class VI wells are compatible with fluids with which they may come into contact and meet or exceed standards developed for such materials by API or ASTM International, or comparable standards approved by the Director, as provided at §146.86(b)(1). However, EPA clarifies that each component of the well system must be described by the owner or operator and will be evaluated by the Director and must meet the requirements of the GS rule. EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website athttp://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Robert J. Finley Letter ID: 0180 Commenter Organization: Illinois State Geological Survey Comment ID: 23629
Comment: (d)

Use of corrosion resistant materials may not be possible in a number of situations so the "where appropriate" language can leave this provision open to significant argument and difference of opinion. Also, the extent of such materials is open to question. Is chrome steel adequate or is stainless steel required? What is the standard?

Response: EPA clarifies that corrosion-resistant materials and cement are not specifically required in a Class VI injection well. Rather, as stated in §146.86(b)(1), casings and cement and other materials used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards listed in the rule and be compatible with fluids with which the materials may be expected to come into contact. Therefore, some well materials may need to be acid-resistant and some may not if they do not come in contact with the CO2 stream or other corrosive fluids and if approved by the Director.

The Director will evaluate the appropriateness of the proposed well construction based on sitespecific information about the injection project, including injection pressures, injection and confining zone lithology, and information about the carbon dioxide stream as provided in §146.86(b)(1). In addition to the flexibility given to the owner and operator, Director's discretion is specifically provided in §146.86(b)(1) for casing and cementing and §146.86(c)(2 and 3) for tubing and packer location and type. 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.

Commenter Name: Thomas Curtis Letter ID: 0181 Commenter Organization: American Water Works Association (AWWA) Comment ID: 23694 Other EPA Comment Codes and Descriptions: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment)
Comment: Group: Well Construction

EPA Request for Comment: EPA seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion resistant casing. EPA Notice 43510.

EPA seeks comment on the merits of requiring down-hole shut-off valves in GS
wells. EPA Notice 43511.

AWWA Response: AWWA recommends that injection wells be constructed from degradation-resistant materials to prevent carbon dioxide from escaping from aportion of the injection well that may have been compromised due to noncompatible materials. AWWA also recommends that down-hole shut-off valves be required for all injection wells. These valves can be a first line of defense against contamination of USDWs due to faulty injection practices. Furtherresearch is needed by both EPA and DOE to identify specific construction methods that would prevent degradation of the well and the carbon sequestration site. AWWA recommends the creation of a certification program that would be used to guarantee that existing or newly developed construction methods are approved for use with geologic sequestration.

Response: EPA agrees that the use of non-compatible materials can result in degradation and failure of the well and could ultimately endanger a USDW. Under §146.86(b)(1), casings and cement and other materials used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards listed in the rule and be compatible with fluids with which the materials may be expected to come into contact. Therefore, some well materials may need to be acid-resistant and some may not if they do not come in contact with the CO2 stream or other corrosive fluids and if approved by the Director.

EPA disagrees that the rule should contain a construction method certification program. EPA believes that the prescribed construction requirements for Class VI wells are sufficient to protect USDWs from endangerment. EPA adds that the requirement at §146.86(b)(1) that materials must meet or exceed standards developed by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director invokes the expertise of these bodies without the added burden of a certification program.

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.

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 such devices are 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 Directors 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.

Commenter Name: Thomas Curtis Letter ID: 0181 Commenter Organization: American Water Works Association (AWWA) Comment ID: 23736 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Part 146.86(b)(1)(v) The corrosiveness evaluation should include the possible combining of the carbon dioxide stream and the injection zone water, which has a higher potential to corrode than the carbon dioxide alone. AWWA recommends revising this part to read:Corrosiveness, chemical compatibility and reactivity of the carbon dioxide stream and the formation fluids located within the injection zone.

Response: EPA clarifies that reference to corrosiveness of the CO2 stream in §146.86 refers to the potential for CO2 to be corrosive in the presence of water or formation fluids. EPA believes that 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24342
Comment: 2. Materials of Construction

Besides specifying additional construction requirements, the proposed rule wouldrequire the use of degradation-resistant construction materials such as acidresistant cement and a corrosion-resistant casing. 73 Fed. Reg. at 43510. These requirements are based on the premise that CO2 is corrosive and that experience with CO2 injection in the EOR context suggests that corrosion is a significant issue. 73 Fed. Reg. at 43509-10.

In fact, CO2 is not corrosive. What is corrosive is carbonic acid formed through the interaction of CO2 and water. This distinction is critical from a practical standpoint, because injected CO2 streams would at least generally be "dry" (i.e., dehydrated) and therefore non-corrosive. Once injected, the "dry" CO2 would come into contact with naturally-occurring water in the subsurface, creating carbonic acid. However, an injection well would inject CO2 far more rapidly than the CO2 could mix with water, creating a CO2 plume that would immediately displace water away from the point of injection. While some residual water saturation would remain, the potential for carbonic acid formation in the immediate vicinity of the injection well would be limited. In this situation - which can be expected to be typical in the carbon sequestration context - there is no basis to suggest that injected CO2 is corrosive or that injection wells must be designed and constructed to resist a severely corrosive environment.

Class II experience with CO2 injection supports this conclusion. Corrosion is sometimes an issue for injection wells used to produce "wet" streams containing oil, brine, and CO2 fractions brought up in the course of EOR/EGR operations. However - and this is the relevant point in the GS context - "dry" CO2 injection systems have operated for many years without the need for corrosion-resistant construction or the occurrence of corrosion-related problems.

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

It should also be noted that the choice of casing and cement materials should be based on planned operating life of the injection well, not the ultimate durationof the GS program. The potential for longer term exposure of well components after injection has ceased will depend upon - and can be mitigated by - measures implemented at closure, such as plugging.

Response: EPA clarifies that it is when CO2 is in the presence of water or formation fluids that it can be corrosive to well materials. Reference to corrosiveness of the CO2 stream in §146.86 is intended to mean CO2 in the presence of water or formation fluids. EPA also notes that while a "dry out zone" (i.e., an area that is free of liquids) might form during injection (e.g., Birkholzer et al, 2008), no modeling study or other information is available about the 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 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24526 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: Rule Provisions or Federal Register Cite: 146.86, 73 FR 43510 EPA Preamble Question: 19. EPA seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion resistant casing. EPA Notice 43510.

CSC Response: The well should be looked at as a system such that not each individual component needs to be CO2 resistant as long as the entire system provides an effective barrier under the subsurface conditions. Industry experience with CO2 EOR strongly supports the use of conventional oil field tubing, casing, and cements. Industry experience over the past 35 years has led to the development of corrosion mitigation measures (e.g. plastic or epoxy lined tubing, use of corrosion inhibitors, and proper dehydration of CO2) that provide a high degree of protection and mitigate any corrosive effects of injected CO2.

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 manycorrosion mitigation measures that would be appropriate for the design of Class VI wells.

EPA believes that the GS rule provides flexibility: it does not specify materials to be used. Rather, it provides owners or operators with the flexibility to choose, as long as the materials used in Class VI wells are compatible with fluids with which they may come into contact and meet or exceed standards developed for such materials by API or ASTM International, or comparable standards approved by the Director, as provided at §146.86(b)(1). However, EPA clarifies that each individual component of the well system must be described by the owner or operator and will be evaluated by the Director and must meet the requirements of the GS rule.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24589 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: Rule Provisions: 146.86, 73 FR 43510EPA Rule Issue: 19. EPA seeks comment regarding requirements for degradationresistant well construction materials, such as acid-resistant cements and corrosion resistant casing. EPA Notice 43510.

Anadarko Petroleum Corporation (APC) Response: The well should be looked at as a system such that not each individual component needs to be CO2 resistant as long as the entire system provides an effective barrier under the subsurface conditions. Industry experience with CO2 EOR strongly supports the use of conventional oil field tubing, casing, and cements. Wells cemented with basic cement that have been exposed to CO2 for several decades have demonstrated minimal degradation and have been protective of USDWs (Reference: Crow. CO2 Capture Project Field Study of a Wellbore from a Natural CO2 Reservoir).

Industry experience over the past 35 years has led to the development of corrosion mitigation measures (e.g. plastic or epoxy lined tubing, use of corrosion inhibitors, and proper dehydration of CO2) that provide a high degree of protection and mitigate any corrosive effects of injected CO2.

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced recovery, and that this practice has led to the development of many corrosion mitigation measures that would be appropriate for the design of Class VI wells.

EPA believes that the GS rule provides flexibility: it does not specify materials to be used. Rather, it provides owners or operators with the flexibility to choose, as long as the materials used in Class VI wells are compatible with fluids with which they may come into contact and meet or exceed standards developed for such materials by API or ASTM International, or comparable standards approved by the Director, as provided at §146.86(b)(1). However, EPA clarifies that each individual component of the well system must be described by the owner or operator and will be evaluated by the Director and must meet the requirements of the GS rule.See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: John King Letter ID: 0211 Commenter Organization: Shell Exploration and Production Company (SEPCo) Comment ID:

22771 Other EPA Comment Codes and Descriptions: 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 wouldrequire 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 "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 forany 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.

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 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 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.

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.

Commenter Name: Diane VanDe Hei Letter ID: 0213 Commenter Organization: Association of Metropolitan Water Agencies Comment ID:(AMWA) 22945 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: - 73 FR 43510 -EPA seeks comment regarding requirements for degradationresistant well construction materials, such as acid-resistant cements and corrosion resistant casing.

Response: AMWA agrees that cement and other materials used for carbon sequestration well construction must be resistant to corrosion and other potential chemical reactions in the subsurface. As stated earlier AMWA also recommends that additional materials research be performed.

Response: EPA agrees that the use of non-compatible materials can result in degradation and failure of the well and could ultimately endanger a USDW. Under §146.86(b)(1), casings and cement and other materials used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards listed in the rule and be compatible with fluids with which the materials may be expected to come into contact. Therefore, some well materials may need to be acid-resistant and some may not if they do not come in contact with the CO2 stream or other corrosive fluids and if approved by the Director.

EPA continues to actively monitor ongoing research on GS and related subtopics. The Agency actively tracks more than two dozen DOE pilot projects, which are providing practical knowledge and field experience in the early deployment of GS injection wells. The Agency discussed three specific projects in the Notice of Data Availability and Request for Comment: the Aneth field ER project; the Escatawpa, Mississippi saline basin project; and the Pump Canyon Unmineable coal seam project. EPA has also reviewed information from several international large-scale commercial GS operations.

EPA plans to, every six years, collect and review project data on early GS projects, including site characterization, operational, monitoring, and modeling 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.

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24280 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: 3. The Proposed Rule overstates the corrosivity of CO2, which is not at all corrosive except in the presence of free water.

The third basis for the Proposed Rule is the potential corrosivity of CO2.[FN26] The Proposed Rule specifically seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion-resistant casing. The NOPR correctly states that CO2 mixed with water will form carbonic acid (H2CO3) and that carbonic acid is corrosive of cement -- a fact that has long been taken into account in existing permitting procedures and industry practices. However, the preamble to the Proposed Rule appears to overstate the corrosivity of CO2 under actual geologic storage conditions. For example, the NOPR references (73 Fed. at 43,510) the actualfield experience and observations from wells that had been exposed to a CO2- water environment for 30 years, but then appears to largely dismiss the results on the grounds that this actual field corrosion experience is "surprisingly" low (presumably in light of a referenced laboratory study that found much more rapid corrosion than has in fact been experienced).[FN27] In contrast, a study that reviewed actual samples exposed to a CO2-water environment for 30 years was seemingly dismissed as involving "only limited examples," while the contradictory laboratory study was apparently given greater weight.[FN28]

The Proposed Rule appears to downplay other research publications that conclude that conventional Portland-based well cements have been adequate to guard against corrosion from CO2 mixed with water. For example, the Proposed Rulecites Meyer (2007)[FN29], but doesn’t recognize that Meyer notes that nonPortland cements have not been widely used in CO2 EOR applications, and have been applied instead to resist "very severe acid gas (CO2 and H2S) and highly corrosive geothermal brine exposure conditions." Meyer (2007), supra, n. 4 at 18. Dr. Meyer also noted the actual experience from a 52 year old well with conventional, Portland-based well cement, that had been exposed to CO2 for 30 years in EOR operations and no significant wellbore failure had been observed. Id. (referencing Carey, et al. 2007).[FN30] Indeed, Carey, et al., concluded from the review of actual cement exposed to CO2 for 30 years that "[t]he casing was in excellent condition and showed little evidence of corrosion." Carey, et al., at 76. While the Portland cement did show evidence of exposure to CO2, the structural integrity of the recovered cement core, petrographic observations, air permeameter data, and cement bond log indicated that "the cement retained its capacity to prevent significant transport of fluid through the cement matrix." Id. at 84; see also at 78 ("no obvious evidence for CO2 interaction" inthe shale caprock); id. (core bond log showed "no evidence of CO2- induced debonding or channel formation at or near the reservoir contact"); id. ("most
basic observation of the SACROC core" is that the Portland cement at the studied well "survived and retained its structural integrity after 30 years in a CO2- reservoir environment").

Finally, the record here should be supplemented with additional laboratory research published after the Proposed Rule, the results of which suggest a rate of degradation of Portland cement under conditions mimicking geological sequestration that is far less than the study cited in the Proposed Rule. See Kutchko, et al. "Rate of CO2 Attack on Class H Well Cement under Geologic Sequestration Conditions" (hereafter Kutchko, 2008).[FN31] While the details of the research merit careful consideration, and additional research is currently underway, the conclusion of this August 2008 research publication is worth quoting:

Based on the alteration process, penetration depths, and rates of alteration observed in this study, and on penetration depths observed in field samples exposed to CO2 for ~30 years, it is unlikely that alteration of these cements via cement matrix diffusion of supercritical CO2 or CO2-saturated brine would lead to significant alteration in well completions that are properly cemented with Class H neat cement after decades of exposure to supercritical CO2 or CO2-rich brine.Kutchko, et al.(2008), supra, at 6242.

This research is reinforced by other papers presented at a major international conference on greenhouse gas control technologies, the 9th International Conference on Greenhouse Gas Control Technologies (hereafter cited as "GHGT-9") that we commend to the agency’s attention, including in particular:[FN32]

- Duguid, "An estimate of the time to degrade the cement sheath in a well exposed to carbonated brine," summarizing (at 3-4) recent physical research on cement carbonation and describing own research. In sum, Duguid’s recent experiments indicate (at 8) that for a well that has good zonal isolation and no pathways for flow, "the rate of degradation will be between 30,000 and 700,000 years to degrade 25 mm of neat paste in a sandstone reservoir, and possibly longer to destroy the cement passing through the cap rock."[FN33]

- Crow, Williams, Carey, Celia, and Gasda, "Wellbore integrity analysis of a natural CO2 producer," at 8 (concluding, inter alia from analysis of 30 year old well from a natural CO2 production reservoir that Portland-based cement systems "can be used effectively in creating suitable barrier systems for long-term CO2 storage operations, if good practices are employed during well construction");

- Benge, "Improving wellbore seal integrity in CO2 injection wells" (reviewingrecent research and noting (at 2) that applying the formula developed by BarletGouedard, et al., it would take "several hundred centuries" - tens of thousands of years -- to degrade 6 meters of wellbore cement (even assuming a continuous and renewable supply of fresh CO2 with no other inhibiting reactions occurring).

- Aiken, "An Introduction to the IEA GHG International Research Network on Wellbore Integrity." The paper reviews the work of the IEA’s International Research Network on Wellbore Integrity founded some 4 years ago and noting (at 1, 6) the importance of analyzing the differences found between laboratory experiments and corresponding field findings, and if necessary, designing new laboratory experiments to better replicate field conditions.

A great deal of other original research was presented as well, underlining the dynamic nature of research in this area and reinforcing the importance of avoiding overly-prescriptive requirements that are unnecessary based on experience in the field.

We concur with the Proposed Rule’s general principle that cement and cement additives must be "compatible with the carbon dioxide stream and formation fluids" and "of sufficient quality and quantity to maintain integrity over the design life" (Section 146.86 (b) (5)). However, we are concerned that the rule contains prescriptive well construction and monitoring requirements that do not appear necessary in light of actual field experience and the more recent laboratory research referenced above. At a minimum, the more recent research suggests that EPA should defer imposing these additional costly requirements pending the fruits of the further field experience and research.[26] See 73 Fed. Reg. at 43,503 (design changes are being proposed to address mobility "and corrosivity" caused by long term GS of CO2); id., at 43,504 (EPAproposing changes "[b]ecause of" the volumes of CO2 being anticipated for longterm storage, the buoyant and viscous nature of the injectate, "and its corrosivity when mixed with water"); id. at 43,509 (pointing to the "potentially corrosive nature of the injectate" in the design and construction of CO2 GS wells and noting that "CO2 mixed with water or impurities (NOX, SOX and H2S) can be corrosive to well materials and cements" and expressing concern that "conventional" cement formations (e.g. Portland cement) are "potentially vulnerable" to acid attack).

[27] 73 Fed. Reg., at 43,510

[28] Id. ("[a]though the field corrosion looks surprisingly low, these are only limited examples. Laboratory studies are conducted under aggressive chemical conditions in an attempt to mimic the cumulative effects of long-term exposure to CO2-rich formation fluids. Given the high injection rates, long lifespan, and potential impurities in GS, careful selection of acid-resistant materials and practices may be necessary).

[29] Meyer, supra, n.4.

[30] Dr. Meyer references the pre-publication version of Carey, J.W., M. Wigand, S.J. Chipera, G. WoldeGabriel, R. Pawar, P.C. Lichtner, S.C. Wehner M.A. Raines and G.D. Gutherie Jr., "Analysis and Performance of Oil Well Cement with 30 Years of CO2 Exposure from the SACROC Unit, West Texas, USA," preprint submitted to International Journal of Greenhouse Gas Control, October 18, 2006. The citation to the published report is 1 International Journal of Greenhouse Gas Control, pages 75-85 (2007).

[31] Barbara G. Kutchko, Brian R. Strazisar, Gregory V. Lowry, David A. Dzombak, and Niels Thaulow, "Rate of CO2 Attack on Class H Well Cement under Geologic Sequestration Conditions," Environmental Science and Technology, vol. 42, number 16 (August 15, 2008), at 6237-42.

[32] "GHGT-9, 9th International Conference on Greenhouse Gas Control Technologies," (November 16-20, 2008) Washington DC (http://mit.edu/ghgt9/) (hereafter "GHGT-9 Conference" (organized by MIT in collaboration with the IEA Greenhouse Gas R&D Programme (IEA GHG), with major sponsorship from the U.S. Department of Energy). All papers presented at the GHGT-9 Conference are available from the conference website at: http://mit.edu/ghgt9/papers/index.html (last visited December 12, 2008) and through the site’s search portal at: https://www4.eventsinteractive.com/iea/rs.esp?id=270005&scriptid=sppp1 (last visited December 12, 2008).

[33] It should be noted that these results are quite different than in a 2006 paper by some of the same researchers which EPA included among the supporting materials in this proceeding. Compare A. Duguid, M. Radonjic, R. Bruant, T. Mandecki, G. Scherer, and M. Celia "The Effect Of CO2 Sequestration On Oil Well Cements" (Document ID: EPA-HQ-OW-2008-0390-0013) (posted by EPA July 25, 2008).Response: EPA disagrees that the potential corrosion of well materials and cements when exposed to CO2 in the presence of water or other fluids is overstated. While some studies of cement performance have shown encouraging results, other information gathered through stakeholder workshops, research, and field data provide evidence of chemical alteration and suggest a potential for degradation to occur and potentially endanger USDWs.

Although the laboratory and field studies suggest that corrosion problems may not be severe, such problems cannot be conclusively ruled out, and the amount of available data on this topic is still limited. 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 construction requirements at §146.86 are justified.

EPA has reviewed the study by Meyer (2007) cited by the commenter, along with other laboratory and field-based research (Barlet-Gouedard et al., 2006; Kutchko et al., 2007, Carey et al., 2007, and Crow et al., 2008) that have shown Portland cement alteration (carbonation) when the cement is exposed to CO2. While research indicates that cement alteration occurs, the alteration appears not to significantly reduce the integrity or performance of the cement. However, under conditions simulating flowing CO2-saturated brine, loss of structural integrity (more significant degradation) of cement was found in laboratory studies (Duguid et al. 2005), although it is uncertain whether wells in GS operations would be exposed to flowing CO2-saturated brine. The field-based studies that identified alteration reflect the results of relatively few samples from a very small number of wells, and the well material samples may have been exposed primarily to dry CO2. Cement degradationand corrosion are a possibility, so the cement and cement additives used may need to be acidresistant to meet the requirement that they are compatible with the CO2 stream, formation fluids, and the anticipated injection zone conditions.

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24292
Comment: C. § 146.86 Corrosiveness of the carbon dioxide stream, and formation fluids.

Under the proposed rule, the Director is required to determine and specify casing and cementing requirements to ensure that a proposed Class VI well is constructed and completed to prevent the movement of fluids into or between USDWs or into any unauthorized zones and to permit appropriate testing and monitoring. The proposed rule does not adequately explain or justify the information requirements set forth therein.

Response: The final rule does not specifically require the use of acid-resistant cements, but it requires at §146.86(b)(5) that cement and cement additives be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life the GS project. Both field and laboratory studies have found acid alteration where traditional well cements have been used for CO2 injection. Although the laboratory and field studies suggest that corrosion problems may not be severe, such problems cannot be conclusively ruled out, and the amount of available data on this problem is still relatively small. Laboratory investigation of cement degradation is an ongoing research area, and field-based studies are very few. There also does not appear to be a clear consensus at this time on the corrosion risks for the steel components ofinjection wells. Given the anticipated long lifespan of a Class VI well and the difficulties that would be associated with a corrosion-related well failure, EPA believes that the construction requirements at §146.86 are justified.

EPA clarifies that the requirement at §146.86(b)(5) is that cement and cement additives must be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project.

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.

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24293
Comment: 1. EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells.(1) (v) Corrosiveness of the carbon dioxide stream, and formation fluids;

The proposed rule requires an applicant to submit to the Director information on the corrosiveness of the carbon dioxide stream, and formation fluids. Neither the proposed rule nor the Preamble adequately explains whether the information requested is corrosiveness of the combined streams of CO2 and formation fluids, or each independent stream (which seems unnecessary). Further, the proposed rule or the Preamble should elaborate on what type of data may be acceptable - laboratory data for hypothetical streams, empirical testing, analogous wells? Clarification is requested on the aforementioned requirements.

Response: EPA clarifies that it is when CO2 is in the presence of water or formation fluids that it
can be corrosive to well materials. EPA adds that the corrosive characteristics of the CO2-modified formation fluids can be described in a number of technical ways. Corrosiveness should be described by the interaction between the CO2-modified fluid specific to the project and the well component (e.g., the cement, casing, tubing or packer) that could be affected.

EPA adds that, with the permit application, the owner or operator 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 will evaluate the appropriateness of the proposed construction based on site-specific information about the injection project, as specified at §146.86(b)(1). In making this determination, the Director will also have the large array of geologic, geochemical, and hydrologic data on the site that the owner or operator must submit to meet the permit application requirements at §146.82(a). EPA adds that during the permit application process, the owner or operator and the permitting authority should work together to determine the specific tests that are appropriate, based on the site-specific

circumstances.

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.

Commenter Name: Neeraj Gupta Letter ID: 0229Commenter Organization: Battelle Energy Technology (BET) Comment ID: 21845 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: Page 82, Cement and Casing Materials- We suggest that if acid resistant cement and casing are to be required, they should be required only in the injection interval and immediate confining layer, which are most likely to be affected by the CO2 storage zone. The shallower drill strings may use more common materials. This seems a typical practice in most CO2 applications.

Response: EPA clarifies that acid-resistant cement and casing are not specifically required in a Class VI injection well. Rather, as stated in §146.86(b)(1), casings and cement used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards listed in the rule and be compatible with fluids with which the materials may be expected to come into contact. Therefore, some well materials may need to be acid-resistant and some may not if they do not come in contact with the CO2 stream or other corrosive fluids and if approved by the Director.

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.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23241 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: 19. EPA seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion resistant casing. EPA Notice 43510.

Based upon history in carbon dioxide injection projects, construction requirements should be based upon actual needs as identified in these projects and upon actual subsurface conditions. Industry experience with carbon dioxide EOR projects supports the use of conventional tubing, casing, and cements. These wells have been demonstrated to protect USDWs. Corrosion mitigation measures such as lined tubing, use of corrosion inhibitors, and proper dehydration of carbon dioxide provide adequate protection.

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 believes, however, that casings and cement and other materials used must have sufficient strength and be designed for the life of the sequestration project. That is, corrosion mitigation measures, as suggested by the commenter, alone are not sufficient to protect USDWs. For thisreason, the rule requires that materials meet standards established in the rule and be compatible with fluids with which the materials may be expected to come into contact.

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.

Commenter Name: Claire Olson Letter ID: 0260 Commenter Organization: Basin Electric Power Cooperative Comment ID: 22397 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: "3. Proposed Injection Well Construction Requirements"

EPA seeks comments regarding degradation resistant well construction materials, such as acid resistant cements and corrosion resistant casing. Dakota Gasification and Basin Electric agree with EPA's proposal to not specify materials and provide the owner/operator the flexibility to choose materials within the appropriate construction standards. The owner/operator working with the State Director should be in the best position to determine a cost effective strategy for construction, corrosion prevention, and corrosion monitoring that is best suited for the site conditions. For example, Dakota Gasification's CO2 pipeline and much of the Weyburn field systems are constructed from carbon steel, even though this is not common practice in acid gas systems. Due to some of the unique properties of this CO2 stream, the corrosion issues have been insignificant after 9 years of continuous service.

Response: EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility regarding appropriate materials for 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 the materials may be expected to come into contact and meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director, as provided at §146.86(b)(1).

EPA is aware of GS efforts at Weyburn; a paper summarizing EPA's review of Weyburn and other large international GS projects is in the rulemaking docket. 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: 0263 Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22805 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: III A. 3 Proposed Injection Well Construction Requirements

T. EPA seeks comment regarding requirements for degradation-resistant wellconstruction materials, such as acid-resistant cements and corrosion resistant casing.

IOGCC Response: Concerning degradation-resistant well construction materials, the EPA rule should not be overly prescriptive but instead set a performance standard that would allow on a case by case basis the cementing materials necessary to

meet the standard.

Response: EPA clarifies that corrosion-resistant materials are not specifically required in a Class VI injection well. Rather, as stated in §146.86(b)(1), casings and cement and other materials used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards established in the rule and be compatible with fluids with which the materials may be expected to come into contact. EPA believes the rule provides an appropriate amount of flexibility. The construction requirements at §146.86 provide flexibility by listing the basic components a Class VI well must have to prevent endangerment of USDWs, and allow owners or operators to choose appropriate materials in meeting these requirements.

The Director will evaluate the appropriateness of the proposed well construction based on sitespecific information about the injection project, including injection pressures, injection and confining zone lithology, and information about the carbon dioxide stream as provided in §146.86(b)(1). In addition to the flexibility given to the owner and operator, Director's discretion is specifically provided in §146.86(b)(1) for casing and cementing and §146.86(c)(2 and 3) for tubing and packer location and type. 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.

Commenter Name: Brian Williams Letter ID: 0507 Commenter Organization: BP Alternative Energy Comment ID: 21164 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: But first, with regard to well construction, and specifically around the points of corrosion resistant materials and cement. Based on industry experience and field studies, corrosion resistant materials should not be mandated for allprojects, and the requirement, if there is any, should be made on a sitespecific basis. Early field studies, in particular by the CO2 capture project, indicate that it is the appropriate placement of cement and not the type of cement that delivers isolation and prevents casing corrosion.

The choice of casing and cement materials should be selected based on planned well operating life, i.e. decades, and not on the ultimate duration of the storage program itself. The potential for longer term exposure of casing during storage, which might occur after injection has stopped, is mitigated by plugging
the static well with corrosion resistant material.

Response: The rule does not specify cements to be used; rather, it provides owners or operators with the flexibility to choose, as long as the cements are compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project, as specified at §146.86(b)(5).EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility regarding the selection and use of cements for Class VI wells that are appropriate to the site-specific conditions of the project. With the permit application, the owner or operator must submit well construction procedures, as specified at §146.82 (a)(12), that demonstrate that the well as constructed will prevent unacceptable fluid movement; allow the use of appropriate testing devices and workovertools; and allow continuous monitoring of the annulus space between the injection tubing and longstring casing, as specified at §146.86(a). The Director will evaluate the procedures in the context of geological and proposed operating data about the site.

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 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 USDW 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.

Commenter Name: Iain Wright Letter ID: 0508 Commenter Organization: BP Alternative Energy Comment ID: 21182 Other EPA Comment Codes and Descriptions: 3860 2.3.3 Well component degradation
Comment: At In Salah a few miles up from the three CO2 injectors we have four wells that produce natural gas from exactly the same geological formation. The design of the CO2 injectors is identical to the design of natural gas producers, except that the gas producers have stainless steel tubing, whereas, the CO2 injectors have conventional mild steel or L80 tubing. This is because the gas producers are actually in a more corrosive environment than the CO2 injectors.

So just to emphasize that point, the CO2 sequestration wells permit the, in In Salah, are constructed to a lower specification than the natural gas wells in

the same formation.

So we recommend that the design and construction of geo-sequestration wells should be site-specific and fit for the purpose of preventing endangerment to

USDWs.

Response: EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility regarding appropriate materials for 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). The Director will evaluate the owner or operator's proposed construction procedures, including materials to be used, in the context of information about the well, the CO2 stream, and the site, as specified in §146.86(b)(1). EPA is aware of GS efforts at In Salah and clarifies that the wells in question were not constructed in accordance with US regulations, so the comparison is not necessarily analogous. A paper summarizing EPA's review of In Salah and other large international GS projects is in the rulemaking docket.

Commenter Name: Talib Syed Letter ID: 0537
Comment ID: 21476 Other EPA Comment Codes and Descriptions: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)
Comment: So that is about it. I think you are headed in the right direction, but we've got to be careful on, you know, we are going to learn as we go along. We have got a lot of experience that EOR, 70% of the current CO2 injections are the Permian Basin in west Texas. Okay. We started CO2 flooding in west Texas in you know, in the `50's so we have got a lot of information on how to design the wells, what the problems are, but for geosequestration where you are just, you know, storing it in deep seated aquifers, you have got to be careful with the wells. You have got to be careful about you know, the reaction of the tubulars, the reaction on the cement. Again for EOR, if you got a cement like, let us say a problematic cement, that is not going to be effective in preventing flow. It has to be modified and there are now new cements that are coming in for specifically designed for CO2 purposes. So these types of cements may be effective again, but again we have got to watch out for each case and not just a sealed okay if it is there because KBR and Halliburton and all the other service companies are coming up with new cement specifically designed for making sure that in every instance you have got that area covered. Okay?

Response: EPA clarifies that the requirement at §146.86(b)(5) is that cement and cement additives must be compatible with the CO2 stream and formation fluids and of sufficient quality and quantityto maintain integrity over the design life of the GS project. EPA believes that the use of acidresistant cements is one of several protective measures for meeting that Class VI well construction requirement, along with the requirements for surface casing and long-string casing and well tubulars that are compatible with the CO2 and formation fluids. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information.

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).

The Agency plans to, every six years, collect and review data on GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)



### Individual Comments

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22525
Comment: Admixed cements have been "accelerated" tested in the presence of carbonic acid for a period of 6-12 months, but not for decades (personal communication with Vaughn Morgan, Halliburton). Thus, un-field tested specialty cements have been short term laboratory tested, but not over a 50 year period! Halliburton ( http://www.patentstorm.us/patents/6904971.html) makes a acid resistant cement "with improved corrosion resistance.’ Halliburton does not claim the cement to

be acid resistant!

What is particularly disturbing is the statement by EPA at 73 FR 43510, col. 1, "Today’s proposal does not specify materials that may be used, rather, proposes providing the owner or operator with the flexibility to choose, as long as the materials used in GS wells are corrosion-resistant and meet standards approved for such materials by API or ASTM International or comparable standards approved by the [nontechnically trained] Director". This statement says in effect, "We don’t know what materials are appropriate for CS well completions. Thus, EPA places the responsibility on industry and the untrained, non-engineer Regional Director to solve the materials dilemma. This raise questions about the existing EPA/State approved sequestrations wells!

The EPA’s statement at 73 FR 43510 raises even a greater concern:

[t]oday’s proposal would require that the cements and cement additives used in GS wells be appropriate to address long-term injection of CO2 and assure that the well can maintain integrity throughout the proposed life span of the project,

Response: EPA believes that allowing flexibility in choosing cements is an important way to address the potential geologic and operational variation in GS projects. For this reason the rule will allow the selection and use of cements for Class VI wells that are appropriate to the site-specific conditions of each project. The rule at §146.86(b)(5) provides owners or operators with the flexibility to choose cements and additives, as long as they are compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life the GS project.

The materials must also meet the specifications developed by API or ASTM International, or other specifications approved by the Director. This requirement at §146.86 (b)(1) invokes the expertise of these bodies to ensure that the requirements for construction of Class VI wells reflect the state of the art in well construction technology. EPA believes that permitting authorities, which have many staff who have been overseeing UIC programs for decades, have sufficient expertise to evaluate the appropriateness of cements for use in specific situations.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.

Commenter Name: Brian Williams Letter ID: 0116 Commenter Organization: BP Alternative Energy Comment ID: 22050 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: I would like to comment on certain of the incremental requirements in the draft rule, including the preamble, around the design, construction & operation of Class VI wells that we feel are potentially excessive.

WELL CONSTRUCTION

Corrosion resistant materials & cement - Based on industry experience and field studies, corrosion resistant materials should not be mandated for all projects, and the requirement, if there is any, should be made on a site-specific basis. Early field studies (by the CO2 Capture Project) indicate that it is the appropriate placement of cement, and not the type of cement, that delivers isolation & prevents casing corrosion.

Response: EPA agrees that proper cement placement is extremely important to the integrity of a Class VI well. However, even proper cement placement cannot compensate for an improper type ofcement. It is also important that the cement type be appropriately CO2 compatible and corrosionresistant, and suitable to both the CO2 stream and formation fluids. Data from research and the field show that various cement designs are subject to chemical alteration when exposed to CO2 (e.g., Barlet-Gouedard et al., 2006; Kutchko et al., 2007; Carey et al., 2007). 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).

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.

Commenter Name: Brian Williams Letter ID: 0116 Commenter Organization: BP Alternative Energy Comment ID: 22051 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: The choice of casing and cement materials should be selected based on planned well operating life (i.e., decades), not on the ultimate duration of the storage program. The potential for longer term exposure of casing during storage, which might occur after injection has stopped, is mitigated by plugging the static well with corrosion-resistant material, if it is deemed necessary at that time.

Response: EPA disagrees that the casing, cement, or other materials should only be designed for theperiod 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.

Commenter Name: Doug Louis Letter ID: 0121 Commenter Organization: Kansas Corporation Commission Comment ID: 22081
Comment: cemented interval above the injection zone. KCC staff believes an exotic blend of CO2 resistant cement is not warranted considering the proven record of CO2- EOR well-construction history.

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).

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.

Commenter Name: Leslie Savage Letter ID: 0122 Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24783 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: (i) Depth to the injection zone; (ii) Injection pressure, external pressure, internal pressure and axial loading; (iii) Hole size; (iv) Size and grade of all casing strings (E.G., wall thickness, external diameter, nominal weight, length, joint specification and construction material); (v) Corrosiveness of the carbon dioxide stream, and formation fluids; (vi) Down-hole temperatures AND PRESSURES; (vii) Lithology of injection and confining zones; (viii) Type or grade of cement, INCLUDING ADDITIVES; and (ix) Quantity, chemical composition, and temperature of the CO2 stream.

{Redundant - look at application requirements.}Response: EPA agrees with the suggestion that §146.86(b)(1)(viii) be revised to also address cement additives. In the final GS rule, the subparagraph reads as follows: "Type or grade of cement and
cement additives."

EPA clarifies that information on down-hole pressures is required at §146.86(b)(1)(ii).

Commenter Name: Leslie Savage Letter ID: 0122 Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24786 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: (5) Cement and cement additives must be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the WELL geologic sequestration project . The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

{See comment above.}

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 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.

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0127 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 23054
Comment: 9. Completion tubulars are held in place by Portland cement.

10. Portland cement is highly susceptible to Carbonic Acid attack.

11. EPA says, based on a Halliburton ad, safe cement is available.

12. Halliburton says they have tested corrosion resistant cement in the laboratory, under accelerated conditions for 12 months using weight loss as the criteria of satisfaction. When asked if weight loss is a satisfactory criterion the laboratory cement chemist said “We don’t know.” EPA is relying on premature

data.

13. Sequestration of CO2 is forever. A 12 month test against a questionable criterion appears unsafe.Response: EPA disagrees that corrosion-resistant materials and cement do not exist. Industry experience of many decades in corrosive down-hole situations such as acid gas injection and production of natural gas with carbon dioxide and hydrogen sulfide impurities shows that materials are available that can resist corrosive environments. Meyer (2007) lists several types of cements that have been used under such corrosive conditions. EPA acknowledges that studies have likely not been performed to prove a 50-year life span for corrosion-resistant materials. However, there are two studies of wells that were exposed to CO2 for approximately 30 years by Carey et al. (2007) and Crow et al. (2008). Although these studies are limited in the number of well material samples and the number of wells examined, the casing and cement sampled indicate fairly good condition (i.e., fairly significant corrosion resistance) of well materials installed three decades ago. The best available corrosion-resistant materials suited for each GS project will be determined by the Director.

EPA acknowledges that there is limited data on this subject, and believes that providing multiple barriers of protection is the most appropriate approach to protecting USDWs from endangerment. The Agency plans to, every six years, collect and review project data on early GS projects as well as industry innovations on cementing including the development of CO2-resistant epoxy cements 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.

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.

Commenter Name: Emily Rochon Letter ID: 0129 Commenter Organization: Greenpeace International Comment ID: 23072 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: Given the risk of corrosion and leakage, we are strongly supportive of proposal’s language regarding the use of anti- corrosive cements and only allowing anti-corrosive materials for wells. This is an essential requirement to reduce the risks of leaks in the wells which will likely pass through drinking water reservoir and pose the most severe risk to the water supply. Another part

Response: EPA agrees that cement that is compatible with the CO2 and formation fluids will enhance Class VI well integrity. In the interest of USDW protection, the Agency requires that the materials used in Class VI wells must be compatible with fluids with which they may come in contact, as specified in §146.86(b)(1).

EPA adds that the requirements at §146.86(b)(1) state that the materials must meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. This requirement invokes the expertise of these bodies and allows the use of technologies that are yet to be developed.

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.Commenter Name: Robert Bessette Letter ID: 0139 Commenter Organization: Council of Industrial Boiler Owners (CIBO) Comment ID: 23083 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: B. Flexibility in Materials Selection

In the carbon capture and sequestration process, accompanying impurities will likely be incorporated into the carbon dioxide stream and injected in the geologic sequestration zone. As EPA notes, these accompanying particles may have a corrosive effect on the tubing and casing used to contain the carbon dioxide, compromising the safety and security of the sequestration zone. CIBO supports the proposed regulations allowing for variability in setting standards for casing, cementing, and tubing of the Class VI wells. Under the regulations, the Director will determine the standards for these materials on a case-by-case basis, taking into consideration the chemical composition of the carbon dioxide stream.[FN4 Proposed Rule, Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells, 73 Fed. Reg. 43492, 43509-10 (July 25, 2008) (to be codified at 40 C.F.R. §46.86).] CIBO supports this provision is imperative to the safety and security of the carbon capture and sequestration process.

Response: EPA agrees that cement that is compatible with the CO2 and formation fluids willenhance Class VI well integrity. EPA also agrees that developing technology in the field of acidresistant cement will provide the industry with future benefits. In the interest of USDW protection, the Agency requires that the materials used in Class VI wells must be compatible with fluids with which they may come in contact, as specified in §146.86(b)(1).

EPA adds that the requirements at §146.86(b)(1) state that materials must meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. This requirement invokes the expertise of these bodies and allows the use of technologies that are yet to be developed.

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.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141 Commenter Organization: Global Energy, Inc. Comment ID: 23115
Comment: 4.Certainly acid resistant cement represents a modest cost for the benefit of long term well integrity.

Response: EPA acknowledges the comment and agrees that cement that is compatible with the CO2 and formation fluids will enhance Class VI well integrity. EPA also agrees that developing technology in the field of acid-resistant cement will provide the industry with future benefits. In the interest of USDW protection, the Agency requires that the materials used in Class VI wells be compatible with fluids with which they may come in contact, as specified in §146.86(b)(1).EPA adds that the requirements at §146.86(b)(1) state that materials must meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. This requirement invokes the expertise of these bodies and allows the use of technologies that are yet to be developed.

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.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22601 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: Proposed Rule: 146.86(b)(1)

Comment: NGWA supports this provision

Response: EPA agrees that cement that is compatible with the CO2 and formation fluids willenhance Class VI well integrity. EPA also agrees that developing technology in the field of acidresistant cement will provide the industry with future benefits. In the interest of USDW protection, the Agency requires that the materials used in Class VI wells be compatible with fluids with which they may come in contact, as specified in §146.86(b)(1).

EPA adds that the requirements at §146.86(b)(1) state that materials must meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. This requirement invokes the expertise of these bodies and allows the use of technologies that are yet to be developed.

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.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22603
Comment: Proposed Rule: 146.86(b)(5)

Comment: NGWA supports this provision and especially that the assessment should include the radial integrity of the cement.

Response: EPA acknowledges the comment agrees that cement that is compatible with the CO2 and formation fluids will enhance Class VI well integrity. The final rule retains this provision.

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.Commenter Name: Patrick Nugent Letter ID: 0143 Commenter Organization: Texas Pipeline Association (TPA) Comment ID: 23141 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: 8. Imposition of corrosion-resistant materials is too prescriptive.Requirements concerning use of particular materials should be imposed on a caseby-case basis. For example, the regulations should not require that all projects use corrosion-resistant materials, because isolation and corrosion prevention is the result of the proper placement of cement, rather than the type of cement used. Any requirement related to the use of corrosion-resistant materials should be made on a site-by-site basis. Imposition of inflexible, across-the-board materials requirements would unduly hinder development and use of geologic sequestration technology, given that the use of conventional materials will adequately ensure project integrity in many cases.

9. Casing material requirements are similarly prescriptive. Requirements concerning use of particular casing materials should be based on the planned operating life of the injection program, rather than the life of the storage program. Long-term exposure of the casing materials, during storage, can be dealt with through plugging if necessary.

Response: EPA clarifies that corrosion-resistant cement is not specifically required in a Class VI injection well. Rather, as stated in §146.86(b)(1), casings and cement used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards listed in the rule and be compatible with fluids with which the materials may be expected to come into contact. Therefore, some well materials may need to be acid-resistant and some may not if they do not come in contact with the CO2 stream or other corrosive fluids and if approved by

the Director.

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 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.

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.

Commenter Name: James Dooley Letter ID: 0156 Commenter Organization: Joint Global Change Research Institute, Pacific Comment ID:Northwest National Laboratory 22660
Comment: - Page 43509, last full paragraph on that page. The text here seems to imply that the cement used for CO2 storage wells will be eaten away by "acid" in one week. This is one example of a number of places in the rule where "perhaps inadvertently in the editing process" it seems as if text was deleted that would have helped a reader understand that "we are now discussing a scientific study that has some bearing on the topic at hand but isn’t exactly like GS" and "now are switching to an explicit discussion of what the USEPA will require of owners and operators of GS projects." If this text is retained in subsequent interations of the Class VI rule it would be good to explain why this study is germane to regulating GS in the United States and whether the same thing is expected to happen in practice. If cements in wells are going to fail in a week, then there isn’t much point in promulgating this rule.

Response: EPA clarifies that the Duguid et al. (2004) study referenced in the preamble to the proposed rule was only one of many studies it considered when developing the construction requirements for Class VI wells. The laboratory studies of Duguid et al. (2004, 2005) found rapid degradation of cement under conditions of flowing (replenishing) CO2-saturated brines. Other more recent laboratory studies (Barlet-Gouedard et al., 2006; Kutchko et al., 2007) found cement alteration, but no significant degradation (loss of integrity) in experiments that subjected the cement to static (non-replenishing) volumes of CO2. The SACROC well materials sampled and studied also likely were not exposed to flowing (replenishing) acidic brines (Carey et al., 2007). Cement alteration and corrosion were found to occur at differing rates in the various studies researched. The two studies with the most cement alteration were Duguid et al. (2004) (presumably due to exposure to the CO2-brine flux) and Barlet-Gouedard et al., (2006) (perhaps due to the higher experimental temperatures), but EPA notes that other important factors such as pressure, contact with CO2- saturated brine, and time between cement curing and contact with CO2 may have an impact on the

rate of cement corrosion.

Commenter Name: Michael J. Miller Letter ID: 0168 Commenter Organization: Electric Power Research Institute (EPRI) Comment ID: 22498 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment); 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 146.92)
Comment: Preamble, page 43507: "Today’s proposal does not prescribe the specific cements to be used to plug abandoned wells..."

Also, preamble, page 43510: "EPA seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion resistant casing."

EPRI COMMENT #5: We question the adequacy of the evidence employed to justify requiring the use of corrosion resistant cements in all cases. The laboratory study performed by Duguid, et al. (2004) cited by EPA exposed portland cement samples to acidified waters in an aggressive flow configuration uncharacteristic of a borehole environment. In contrast, the field study by Crow, et al. (2008) performed on a 30 year old production well is characteristic of a borehole environment. Side-wall cores of the casing, acoustic bond logs and well integrity tests did not show signs of casing corrosion, leakage or cement-bonddegradation. While side-wall cores of the cement indicated that CO2-induced cement alteration had occurred, the hydraulic integrity of the cement seal was still highly effective. EPA states that the cement alteration found in the study demonstrates that CO2 migrated up the borehole. We question this conclusion and believe the study is not conclusive on this point. Given that the study was performed on a natural CO2 reservoir, free and dissolved CO2 are expected to be present throughout the stratigraphic column from the top of the reservoir through the confining unit to the surface. Therefore, an alternative hypothesis is that the native CO2 present in the confining unit or caprock adjacent to the
cement seal caused the observed alteration. Evidence that the cement underwent greater alteration at the cement-formation interface adjacent to the caprock compared to the cement-casing interface located further from the caprock helps support this hypothesis. Most importantly, the seal maintained its integrity, exhibiting very low cement matrix, and low interface permeabilities, as determined by laboratory and vertical interference tests in the field, respectively. However, should the EPA eventually adopt a requirement for corrosion-resistant materials, we believe EPA is taking the correct approach by not prescribing the type of corrosion-resistant cements and casing to be used in well completions and abandonments; a number of materials are available and selection of a given material may be driven by site-specific well

characteristics.

Duguid, A., M. Radonjic, R. Bruant, T. Mandecki, G. Scherer, and M. Celia. 2004. The Effect of CO2 Sequestration on Oil Well Cements. Presented at the Greenhouse Gas Technologies Conference (GHGT-7), September 5-9, 2004. Vancouver, Canada.

Crow, W., D.B. Williams., B. Carey, M. Celia, and S. Gasda. 2008. CO2 Capture Project Field Study of A Wellbore from a Natural CO2 Reservoir. Presented at the 7th Annual Conference on Carbon Capture and Sequestration, May 5-8, 2008. Pittsburgh, Pennsylvania.

Response: EPA considered both field and lab studies in developing the requirements for Class VI well construction. The Duguid study referenced by the commenter examined a CO2-saturated brine flux condition that may be found in some injection environments such as a saline aquifer. The Crow study mentioned was a well that produced gaseous CO2 from a natural CO2 deposit. In the studies examined, cement alteration and corrosion was found to occur at differing rates. Factors such as contact with brine, temperature, CO2 flux, and time between cement curing and CO2 exposure may all be relevant. See the discussion of Class VI well construction requirements in the preamble to the
final GS rule for additional information.

EPA clarifies that corrosion-resistant cement is not specifically required in a Class VI injection well. Rather, as stated in §146.86(b)(1), casings and cement used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards listed in the rule and be compatible with fluids with which the materials may be expected to come into contact. Therefore, some well materials may need to be acid-resistant and some may not if they do not come in contact with the CO2 stream or other corrosive fluids and if approved by the Director.

EPA clarifies that the GS rule does not prescribe the specific cements to be used to plug abandoned wells in the AoR because industry standards, such as those developed by API or ASTM International, reflect the current state of the science and the expertise of industrial users on CO2-compatible materials, as specified in §146.92(b). Providing flexibility to choose materials for plugging, provided they are compatible with the injected fluid, is consistent with requirements for other injection well classes and will allow operators to utilize improved well technologies as they become available in the future without a need to amend the regulation.

EPA plans to, every six years, collect and review project data on early GS projects and continue to monitor field and laboratory research 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.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24172 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(1)

API Comments: (v) Corrosiveness COMPOSITION of the carbon dioxide stream and formation fluids;

Rationale: There is no method for measurement of "corrosiveness" of a CO2 stream. The relevant information is the composition of the CO2 stream.

Response: EPA clarifies that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and described. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational information that the Director needs to determine appropriate standards for the tubing and packer.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24176 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(5)

API Comments: (5) Cement and cement additives must be compatible SUITABLE
FOR USE with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the designOPERATING life of

the geologic sequestration projectWELL. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

Rationale: Experience with CO2 EOR under the Class II program demonstrates the effectiveness of existing cementing materials and procedures. Standard API cements have been used in numerous CO2 EOR operations with no adverse consequences. Refer to the citations within EPA‘s proposed rule 73 FR 43532- 43533: Carey et al., (2007), Crow et al., (2008), and Meyer, J.P (2007).

Response: EPA disagrees that the casing, cement, or other materials should only be designed for theperiod 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.

EPA recognizes that the oil and gas industry has decades of experience injecting CO2 and has demonstrated the effectiveness of existing cementing materials and procedures. The final GS rule, at §146.86(b)(1), specifies that all casing and cementing or other materials used in the construction of Class VI wells must meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. This requirement invokes the expertise of these bodies to ensure that the requirements for construction of Class VI wells reflect the state of the art in well construction technology. 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.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24234 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: Rule Provisions: 146.86, 73 FR 43510 EPA Preamble Question: 19. EPA seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion resistant casing. EPA Notice 43510.

API Response: The well should be looked at as a system such that not each individual component needs to be CO2 resistant as long as the entire system provides an effective barrier under the subsurface conditions. Industry experience with CO2 EOR strongly supports the use of conventional oil field tubing, casing, and cements. Industry experience over the past 35 years has led to the development of corrosion mitigation measures (e.g. plastic or epoxy lined tubing, use of corrosion inhibitors, and proper dehydration of CO2) that provide a high degree of protection and mitigate any corrosive effects of injected CO2.

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced recovery, and that this practice has led to the development of many corrosion mitigation measures that would be appropriate for the design of Class VI wells.

EPA believes that the GS rule provides flexibility: it does not specify materials to be used; rather, it provides owners or operators with the flexibility to choose, as long as the materials used in Class VI wells are compatible with fluids with which they may come into contact and meet or exceed standards developed for such materials by API or ASTM International, or comparable standards approved by the Director, as provided at §146.86(b)(1). However, EPA clarifies that each componentof the well system must be described by the owner or operator and will be evaluated by the Director and must meet the requirements of the GS rule. 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.

Commenter Name: Frederick R. Eames Letter ID: 0178 Commenter Organization: CCS Alliance Comment ID: 23864
Comment: experiments. It is also not known if new CO2 resistant cements will perform as well as conventional cements in terms of emplacement and bonding.

Response: EPA notes that corrosion-resistant materials and cement do exist. Industry experience of many decades in corrosive down-hole situations such as acid gas injection and production of natural gas with carbon dioxide and hydrogen sulfide impurities shows that materials are available that can resist corrosive environments. Meyer (2007) lists several types of cements that have been used under such corrosive conditions. EPA acknowledges that studies have likely not been performed to prove a 50-year life span for corrosion-resistant materials. However, there are two studies of wells that were exposed to CO2 for approximately 30 years by Carey et al. (2007) and Crow et al. (2008). Although these studies are limited in the number of well material samples and the number of wells examined, the casing and cement sampled indicate fairly good condition (i.e., fairly significant corrosion resistance) of well materials installed three decades ago. The best available corrosion-resistant materials suited for each GS project will be determined by the Director.

EPA acknowledges that there is limited data on this subject, and believes that providing multiple barriers of protection is the most appropriate approach to protecting USDWs from endangerment. EPA anticipates further findings on the use of acid-resistant cements, in particular the physical integrity of such modified cements in place. The Agency plans to, every six years, collect and review data on GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Commenter Name: Thomas Curtis Letter ID: 0181 Commenter Organization: American Water Works Association (AWWA) Comment ID: 23737 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Part 146.86(b)(1)(viii)AWWA recommends revising this part to read:

Type or grade of cement and chemical compatibility and reactivity of cement and formation fluids located within the injection zone.

Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment EPA has made many revisions to the GS rule. Please see the final rule and the discussion of financial responsibility in the preamble for additional information.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24445 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(1)(v)Proposed CCS Group Recommendations: (v) Corrosiveness COMPOSITION of the carbon dioxide stream and formation fluids;

Basis for CCS Group Comments: There is no method for measurement of "corrosiveness" of a CO2 stream. The relevant information is the composition of
the CO2 stream.

Response: EPA clarifies that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and described. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational information that the Director needs to determine appropriate standards for the tubing and packer.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24451 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(5)

Proposed CCS Group Recommendations: (5) Cement and cement additives must be compatible SUITABLE FOR USE with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the designOPERATING life of the geologic sequestration projectWELL. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

Basis for CCS Group Comments: Experience with CO2 EOR under the Class II program demonstrates the effectiveness of existing cementing materials and procedures. Standard API cements have been used in numerous CO2 EOR operations with no adverse consequences. Refer to the citations within EPA’s proposed rule 73 FR 43532-43533: Carey et al., (2007), Crow et al., (2008), and Meyer, J.P (2007).

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced recovery, and that this practice has led to the development of many corrosion mitigation measures that would be appropriate for the design of Class VI wells.

EPA believes that the GS rule provides flexibility: it does not specify materials to be used; rather, it provides owners or operators with the flexibility to choose, as long as the materials used in Class VI wells are compatible with fluids with which they may come into contact and meet or exceed standards developed for such materials by API or ASTM International, or comparable standards approved by the Director, as provided at §146.86(b)(1). However, EPA clarifies that each individual component of the well system must be described by the owner or operator and will be evaluated by the Director and must meet the requirements of the GS rule.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24526 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: Rule Provisions or Federal Register Cite: 146.86, 73 FR 43510 EPA Preamble Question: 19. EPA seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion resistant casing. EPA Notice 43510.

CSC Response: The well should be looked at as a system such that not each individual component needs to be CO2 resistant as long as the entire system provides an effective barrier under the subsurface conditions. Industry experience with CO2 EOR strongly supports the use of conventional oil field tubing, casing, and cements. Industry experience over the past 35 years has led to the development of corrosion mitigation measures (e.g. plastic or epoxy lined tubing, use of corrosion inhibitors, and proper dehydration of CO2) that provide a high degree of protection and mitigate any corrosive effects of injected CO2.

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced recovery, and that this practice has led to the development of many corrosion mitigation measures that would be appropriate for the design of Class VI wells.

EPA believes that the GS rule provides flexibility: it does not specify materials to be used. Rather, it provides owners or operators with the flexibility to choose, as long as the materials used in Class VI wells are compatible with fluids with which they may come into contact and meet or exceed standards developed for such materials by API or ASTM International, or comparable standards approved by the Director, as provided at §146.86(b)(1). However, EPA clarifies that each individual component of the well system must be described by the owner or operator and will be evaluated by the Director and must meet the requirements of the GS rule.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24567 Other EPA Comment Codes and Descriptions: 3822 2.3.1.1 Depth of surface casing (seeking comment)
Comment: completed in the field. One of these misconceptions is the cementing requirements; both the requirement to cement to surface as well as the use of corrosion-resistant cement. It has been demonstrated that a good cement job is more important than a resistant cement, and in certain cases, the resistant cements proved more susceptible to degradation than a basic well cement. Also, research performed at SACROC has demonstrated the effectiveness of the current Class II program's cementing requirements. Many of the requirements currently proposed do not afford any extra protection to USDWs and in many cases may actually present greater risk.Response: EPA agrees that proper cement installation is critical to maintaining injection well integrity and clarifies that the requirement at §146.86(b)(5) is that cement and cement additives must be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project. It should be noted that in Carey et al. (2007), their research on the ER- CO2 injection well at SACROC was unable to determine whether CO2 in the presence of water, dry CO2, or a CO2-brine mixture had caused the cement alteration observed. In Crow et al. (2008), the well materials studied were from a production well producing from a natural CO2 deposit that also produced associated water, so well materials were presumably exposed to CO2 in the presence of water. Meyer (2007) acknowledges the Carey study found no loss of hydraulic integrity after 30 years, but also mentions the use of acid-resistant cements in wells used for acid gas injection and where brine is encountered.

EPA is unaware of studies showing that the resistant cements proved more susceptible to degradation than basic well cement. However, the Agency clarifies that the final rule requires at §146.86(b)(5) that cement and cement additives be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project. If certain cements have been shown to degrade, they may not be used in Class VI wells.

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 anticipates further findings in the use of acid-resistant cements, in particular the physical integrity of such modified cements in place. The Agency plans to, every six years, collect and review data on GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24589 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: Rule Provisions: 146.86, 73 FR 43510EPA Rule Issue: 19. EPA seeks comment regarding requirements for degradationresistant well construction materials, such as acid-resistant cements and corrosion resistant casing. EPA Notice 43510.

Anadarko Petroleum Corporation (APC) Response: The well should be looked at as a system such that not each individual component needs to be CO2 resistant as long as the entire system provides an effective barrier under the subsurface conditions. Industry experience with CO2 EOR strongly supports the use of conventional oil field tubing, casing, and cements. Wells cemented with basic cement that have been exposed to CO2 for several decades have demonstrated minimal degradation and have been protective of USDWs (Reference: Crow. CO2 Capture Project Field Study of a Wellbore from a Natural CO2 Reservoir).

Industry experience over the past 35 years has led to the development ofcorrosion mitigation measures (e.g. plastic or epoxy lined tubing, use of corrosion inhibitors, and proper dehydration of CO2) that provide a high degree of protection and mitigate any corrosive effects of injected CO2.

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced recovery, and that this practice has led to the development of many corrosion mitigation measures that would be appropriate for the design of Class VI wells.

EPA believes that the GS rule provides flexibility: it does not specify materials to be used. Rather, it provides owners or operators with the flexibility to choose, as long as the materials used in Class VI wells are compatible with fluids with which they may come into contact and meet or exceed standards developed for such materials by API or ASTM International, or comparable standards approved by the Director, as provided at §146.86(b)(1). However, EPA clarifies that each individual component of the well system must be described by the owner or operator and will be evaluated by the Director and must meet the requirements of the GS rule.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24672 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.86(b)(1)(v)

Anadarko Petroleum Corporation (APC) Comments: (v) Corrosiveness COMPOSITION of the carbon dioxide stream and formation fluids;

Rationale: There is no method for measurement of "corrosiveness" of a CO2 stream. The relevant information is the composition of the CO2 stream.

Response: The suggested revision to refer to CO2 "composition" would be less precise. EPA clarifies that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and described. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational information that the Director needs to determine appropriate standards for the tubing and packer.

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.

Commenter Name: John King Letter ID: 0211 Commenter Organization: Shell Exploration and Production Company (SEPCo) Comment ID:

22771 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistantconstruction materials (seeking comment)
Comment: 2. Materials of Construction

Besides specifying additional construction requirements, the proposed rule wouldrequire 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 "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.

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 forthe 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 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 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.

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.

Commenter Name: Diane VanDe Hei Letter ID: 0213 Commenter Organization: Association of Metropolitan Water Agencies (AMWA) Comment ID:

22945 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: - 73 FR 43510 -EPA seeks comment regarding requirements for degradationresistant well construction materials, such as acid-resistant cements and corrosion resistant casing.

Response: AMWA agrees that cement and other materials used for carbon sequestration well construction must be resistant to corrosion and other potential chemical reactions in the subsurface. As stated earlier AMWA also recommends that additional materials research be performed.Response: EPA agrees that the use of non-compatible materials can result in degradation and failure of the well and could ultimately endanger a USDW. Under §146.86(b)(1), casings and cement and other materials used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards listed in the rule and be compatible with fluids with which the materials may be expected to come into contact. Therefore, some well materials may need to be acid-resistant and some may not if they do not come in contact with the CO2 stream or other corrosive fluids and if approved by the Director.

EPA continues to actively monitor ongoing research on GS and related subtopics. The Agency actively tracks more than two dozen DOE pilot projects, which are providing practical knowledge and field experience in the early deployment of GS injection wells. The Agency discussed three specific projects in the Notice of Data Availability and Request for Comment: the Aneth field ER project; the Escatawpa, Mississippi saline basin project; and the Pump Canyon Unmineable coal seam project. EPA has also reviewed information from several international large-scale commercial GS operations.

EPA plans to, every six years, collect and review project data on early GS projects, including site characterization, operational, monitoring, and modeling 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.

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24280 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: 3. The Proposed Rule overstates the corrosivity of CO2, which is not at all corrosive except in the presence of free water.

The third basis for the Proposed Rule is the potential corrosivity of CO2.[FN26] The Proposed Rule specifically seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion-resistant casing. The NOPR correctly states that CO2 mixed with water will form carbonic acid (H2CO3) and that carbonic acid is corrosive of cement -- a fact that has long been taken into account in existing permitting procedures and industry practices. However, the preamble to the Proposed Rule appears to overstate the corrosivity of CO2 under actual geologic storage conditions. For example, the NOPR references (73 Fed. at 43,510) the actual field experience and observations from wells that had been exposed to a CO2- water environment for 30 years, but then appears to largely dismiss the results on the grounds that this actual field corrosion experience is "surprisingly" low (presumably in light of a referenced laboratory study that found much more rapid corrosion than has in fact been experienced).[FN27] In contrast, a study that reviewed actual samples exposed to a CO2-water environment for 30 years was seemingly dismissed as involving "only limited examples," while the contradictory laboratory study was apparently given greater weight.[FN28]

The Proposed Rule appears to downplay other research publications that conclude that conventional Portland-based well cements have been adequate to guardagainst corrosion from CO2 mixed with water. For example, the Proposed Rulecites Meyer (2007)[FN29], but doesn’t recognize that Meyer notes that nonPortland cements have not been widely used in CO2 EOR applications, and have been applied instead to resist "very severe acid gas (CO2 and H2S) and highly corrosive geothermal brine exposure conditions." Meyer (2007), supra, n. 4 at 18. Dr. Meyer also noted the actual experience from a 52 year old well with conventional, Portland-based well cement, that had been exposed to CO2 for 30 years in EOR operations and no significant wellbore failure had been observed. Id. (referencing Carey, et al. 2007).[FN30] Indeed, Carey, et al., concluded from the review of actual cement exposed to CO2 for 30 years that "[t]he casing was in excellent condition and showed little evidence of corrosion." Carey, et al., at 76. While the Portland cement did show evidence of exposure to CO2, the structural integrity of the recovered cement core, petrographic observations, air permeameter data, and cement bond log indicated that "the cement retained its capacity to prevent significant transport of fluid through the cement matrix." Id. at 84; see also at 78 ("no obvious evidence for CO2 interaction" inthe shale caprock); id. (core bond log showed "no evidence of CO2- induced debonding or channel formation at or near the reservoir contact"); id. ("most
basic observation of the SACROC core" is that the Portland cement at the studied well "survived and retained its structural integrity after 30 years in a CO2- reservoir environment").

Finally, the record here should be supplemented with additional laboratory research published after the Proposed Rule, the results of which suggest a rate of degradation of Portland cement under conditions mimicking geological sequestration that is far less than the study cited in the Proposed Rule. See Kutchko, et al. "Rate of CO2 Attack on Class H Well Cement under Geologic Sequestration Conditions" (hereafter Kutchko, 2008).[FN31] While the details of the research merit careful consideration, and additional research is currently underway, the conclusion of this August 2008 research publication is worth quoting:

Based on the alteration process, penetration depths, and rates of alteration observed in this study, and on penetration depths observed in field samples exposed to CO2 for ~30 years, it is unlikely that alteration of these cements via cement matrix diffusion of supercritical CO2 or CO2-saturated brine would lead to significant alteration in well completions that are properly cemented with Class H neat cement after decades of exposure to supercritical CO2 or CO2-rich brine.

Kutchko, et al.(2008), supra, at 6242.

This research is reinforced by other papers presented at a major international conference on greenhouse gas control technologies, the 9th International Conference on Greenhouse Gas Control Technologies (hereafter cited as "GHGT-9") that we commend to the agency’s attention, including in particular:[FN32]

- Duguid, "An estimate of the time to degrade the cement sheath in a well exposed to carbonated brine," summarizing (at 3-4) recent physical research on cement carbonation and describing own research. In sum, Duguid’s recent experimentsindicate (at 8) that for a well that has good zonal isolation and no pathways for flow, "the rate of degradation will be between 30,000 and 700,000 years to degrade 25 mm of neat paste in a sandstone reservoir, and possibly longer to destroy the cement passing through the cap rock."[FN33]

- Crow, Williams, Carey, Celia, and Gasda, "Wellbore integrity analysis of a natural CO2 producer," at 8 (concluding, inter alia from analysis of 30 year old well from a natural CO2 production reservoir that Portland-based cement systems "can be used effectively in creating suitable barrier systems for long-term CO2 storage operations, if good practices are employed during well construction");

- Benge, "Improving wellbore seal integrity in CO2 injection wells" (reviewingrecent research and noting (at 2) that applying the formula developed by BarletGouedard, et al., it would take "several hundred centuries" - tens of thousands of years -- to degrade 6 meters of wellbore cement (even assuming a continuous and renewable supply of fresh CO2 with no other inhibiting reactions occurring).

- Aiken, "An Introduction to the IEA GHG International Research Network on Wellbore Integrity." The paper reviews the work of the IEA’s International Research Network on Wellbore Integrity founded some 4 years ago and noting (at 1, 6) the importance of analyzing the differences found between laboratory experiments and corresponding field findings, and if necessary, designing new laboratory experiments to better replicate field conditions.

A great deal of other original research was presented as well, underlining the dynamic nature of research in this area and reinforcing the importance of avoiding overly-prescriptive requirements that are unnecessary based on experience in the field.

We concur with the Proposed Rule’s general principle that cement and cement additives must be "compatible with the carbon dioxide stream and formation fluids" and "of sufficient quality and quantity to maintain integrity over the design life" (Section 146.86 (b) (5)). However, we are concerned that the rule contains prescriptive well construction and monitoring requirements that do not appear necessary in light of actual field experience and the more recent laboratory research referenced above. At a minimum, the more recent research suggests that EPA should defer imposing these additional costly requirements pending the fruits of the further field experience and research.

[26] See 73 Fed. Reg. at 43,503 (design changes are being proposed to address mobility "and corrosivity" caused by long term GS of CO2); id., at 43,504 (EPAproposing changes "[b]ecause of" the volumes of CO2 being anticipated for longterm storage, the buoyant and viscous nature of the injectate, "and its corrosivity when mixed with water"); id. at 43,509 (pointing to the "potentially corrosive nature of the injectate" in the design and construction of CO2 GS wells and noting that "CO2 mixed with water or impurities (NOX, SOX and H2S) can be corrosive to well materials and cements" and expressing concern that "conventional" cement formations (e.g. Portland cement) are "potentially vulnerable" to acid attack).[27] 73 Fed. Reg., at 43,510

[28] Id. ("[a]though the field corrosion looks surprisingly low, these are only limited examples. Laboratory studies are conducted under aggressive chemical conditions in an attempt to mimic the cumulative effects of long-term exposure to CO2-rich formation fluids. Given the high injection rates, long lifespan, and potential impurities in GS, careful selection of acid-resistant materials and practices may be necessary).

[29] Meyer, supra, n.4.

[30] Dr. Meyer references the pre-publication version of Carey, J.W., M. Wigand, S.J. Chipera, G. WoldeGabriel, R. Pawar, P.C. Lichtner, S.C. Wehner M.A. Raines and G.D. Gutherie Jr., "Analysis and Performance of Oil Well Cement with 30 Years of CO2 Exposure from the SACROC Unit, West Texas, USA," preprint submitted to International Journal of Greenhouse Gas Control, October 18, 2006. The citation to the published report is 1 International Journal of Greenhouse Gas Control, pages 75-85 (2007).

[31] Barbara G. Kutchko, Brian R. Strazisar, Gregory V. Lowry, David A. Dzombak, and Niels Thaulow, "Rate of CO2 Attack on Class H Well Cement under Geologic Sequestration Conditions," Environmental Science and Technology, vol. 42, number 16 (August 15, 2008), at 6237-42.

[32] "GHGT-9, 9th International Conference on Greenhouse Gas Control Technologies," (November 16-20, 2008) Washington DC (http://mit.edu/ghgt9/) (hereafter "GHGT-9 Conference" (organized by MIT in collaboration with the IEA Greenhouse Gas R&D Programme (IEA GHG), with major sponsorship from the U.S. Department of Energy). All papers presented at the GHGT-9 Conference are available from the conference website at: http://mit.edu/ghgt9/papers/index.html (last visited December 12, 2008) and through the site’s search portal at: https://www4.eventsinteractive.com/iea/rs.esp?id=270005&scriptid=sppp1 (last visited December 12, 2008).

[33] It should be noted that these results are quite different than in a 2006 paper by some of the same researchers which EPA included among the supporting materials in this proceeding. Compare A. Duguid, M. Radonjic, R. Bruant, T. Mandecki, G. Scherer, and M. Celia "The Effect Of CO2 Sequestration On Oil Well Cements" (Document ID: EPA-HQ-OW-2008-0390-0013) (posted by EPA July 25, 2008).

Response: EPA disagrees that the potential corrosion of well materials and cements when exposed to CO2 in the presence of water or other fluids is overstated. While some studies of cement performance have shown encouraging results, other information gathered through stakeholder workshops, research, and field data provide evidence of chemical alteration and suggest a potential for degradation to occur and potentially endanger USDWs.

Although the laboratory and field studies suggest that corrosion problems may not be severe, such problems cannot be conclusively ruled out, and the amount of available data on this topic is still limited. 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 thecorrosion 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 construction requirements at §146.86 are justified.

EPA has reviewed the study by Meyer (2007) cited by the commenter, along with other laboratory and field-based research (Barlet-Gouedard et al., 2006; Kutchko et al., 2007, Carey et al., 2007, and Crow et al., 2008) that have shown Portland cement alteration (carbonation) when the cement is exposed to CO2. While research indicates that cement alteration occurs, the alteration appears not to significantly reduce the integrity or performance of the cement. However, under conditions simulating flowing CO2-saturated brine, loss of structural integrity (more significant degradation) of cement was found in laboratory studies (Duguid et al. 2005), although it is uncertain whether wells in GS operations would be exposed to flowing CO2-saturated brine. The field-based studies that identified alteration reflect the results of relatively few samples from a very small number of wells, and the well material samples may have been exposed primarily to dry CO2. Cement degradationand corrosion are a possibility, so the cement and cement additives used may need to be acidresistant to meet the requirement that they are compatible with the CO2 stream, formation fluids, and the anticipated injection zone conditions.

Commenter Name: Edward Steadman Letter ID: 0220 Commenter Organization: The Energy and Environmental Research Center at the University of North Dakota Comment ID:

21622
Comment: Page 43507. Corrective Action. Regarding the use of specific cements in GS wells: The document states that the EPA proposal does not prescribe the specific cements to be used to plug abandoned wells, but in the next paragraph states that corrosion-resistant cements would be required. This is contradictory. EPA must clarify this issue.

Pages 43509 to 43510. Well Component Degradation. Regarding cements:

It is frustrating that the EPA discounts real-world, field-based data in favor of laboratory-generated data and models. In this case, it describes laboratory work that had somewhat contradictory results and acknowledge that "... field studies show clear evidence of reactions between CO2 and well cement, but do notshow such severe corrosion." EPA then goes on to mention two instances of fieldbased research that show only limited effects of CO2 on cements. But as they historically have been known to do (EPA rulings on air quality issues in southwestern North Dakota being just one example), EPA chooses to ignore the
real-world data and make decisions based on the dire results of tests conducted on small samples under laboratory conditions that can be applied only to a very narrow set of subsurface conditions, if at all. The result of this is that the proposal can be interpreted to require the use of relatively new and expensive corrosion-resistant cements rather than cements that have already been used successfully at large-scale CO2 injection sites, in some cases for decades. One potential unintended consequence of this requirement is that the mechanical integrity of these new cements under deeper reservoir pressure and temperature conditions may not be completely understood, especially over time. Again, flexibility should be allowed with respect to the selection of cements.

Response: Regarding corrective action requirements, EPA clarifies that all corrective actionperformed under §146.84(d) must be appropriate to the GS site to ensure that the well does not allow CO2 or other fluids to move into or endanger USDWs. EPA is developing guidance on AoR and corrective action at GS Class VI sites to assist owners or operators and Directors in evaluating requirements and proposed AoR and corrective action plans under §146.84. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Regarding cementing requirements, EPA disagrees that the potential corrosion of well materials and cements when exposed to CO2 in the presence of water or other fluids is overstated. While some studies of cement performance have shown encouraging results, other information gathered through stakeholder workshops, research, and field data provide evidence of chemical alteration and suggest a potential for degradation to occur and potentially endanger USDWs.

EPA clarifies that the requirement at §146.86(b)(5) is that cement and cement additives must be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project. EPA believes that the use of acid-resistant cements is one of several protective measures for meeting that Class VI well construction requirement, along with the requirements for surface casing and long-string casing and well tubulars that are compatible with the CO2 and formation fluids. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information.

EPA clarifies that it has reviewed both laboratory and field-based research (Barlet-Gouedard et al., 2006; Kutchko et al., 2007, Carey et al., 2007, and Crow et al., 2008) that have shown Portland cement alteration (carbonation) when the cement is exposed to CO2. While research indicates that cement alteration occurs, the alteration appears not to significantly reduce the integrity or performance of the cement. However, under conditions simulating flowing CO2-saturated brine, loss of structural integrity (more significant degradation) of cement was found in laboratory studies (Duguid et al. 2005), although it is uncertain whether wells in GS operations would be exposed to flowing CO2-saturated brine. The field-based studies that identified alteration reflect the results of relatively few samples from a very small number of wells, and the well material samples may have been exposed primarily to dry CO2. Cement degradation and corrosion are a possibility, so the cement and cement additives used may need to be acid-resistant to meet the requirement that they are compatible with the CO2 stream, formation fluids, and the anticipated injection zone conditions.

Although the laboratory and field studies suggest that corrosion problems may not be severe, such problems cannot be conclusively ruled out, and the amount of available data on this topic is still limited. 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 construction requirements at §146.86 are justified.

The Agency plans to, every six years, collect and review data on GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Commenter Name: Tiffany Rau Letter ID: 0224 Commenter Organization: Hydrogen Energy International Comment ID: 21680
Comment: (3) Specific CommentsIn addition to the foregoing, HEI respectfully submits the following areas of specific comment:

(i) Well Design and Construction To Avoid Corrosion

One area of comment requested by EPA relates to requirements for "degradationresistant well construction materials, such as acid-resistant cements and corrosion resistant casing." (73 Fed. Reg. at 43510) Based upon historical industry experience and field studies, this would be an excessive requirement and not reasonably necessary to protect USDWs. Risk Profile of a CO2 Geological Storage Project: Wells, by Christopher, Crow, Dodds, Wright, Williams, March

2008.

HEI strongly discourages EPA from setting a requirement to use degradationresistant materials & cement. Actual field observations based upon sampling of in situ casing and annular cements do not support this general requirement. The studies referenced by EPA in its Preamble exposed cement in a laboratory setting to a continuously-refreshed supply of CO2-saturated brine, which then reportedly caused the cement to degrade. (Duguid et al., 2004 and Kutchko et al., 2007.) These studies represent variations in cement alteration rates due to curing and exposure conditions, but neither supports the requirement for the use of degradation-resistant materials and cement because the laboratory procedures that were used do not necessarily represent the actual barrier exposure conditions in an appropriately cemented operating well. Indeed, the findings of Kutchko’s laboratory study suggested there would be limited degradation even after decades, which is consistent with the field study results of Carey et al.,

2007.

EPA’s rulemaking should give considerable weight to documented field surveys which provide more relevant well information, such as those conducted at the SACROC development in the Permian Basin (ref. Carey et al., 2007) and in Colorado (ref. Crow et al, and CO2 Capture Project, 2008). Both of these field studies identified that hydraulic isolation was maintained across the caprock, and the majority of cement reaction was localized to the area near the CO2 interval. Field results indicate it is the appropriate placement of cement, and not the type of cement, that is key to delivery of effective isolation and hence prevention of casing corrosion. Furthermore, cement placement to completely fill the annular space between borehole and casing is the primary means of achieving this objective.

Based on the foregoing, degradation-resistant materials should not be mandated for all projects, without regard to site-specific characteristics. Rather, the application of degradation-resistant materials & cement, if any, should be defined on site-specific characteristics.

Response: The rule does not specify the materials and cements to be used; rather, it provides owners or operators with the flexibility to choose, as long as the cements are compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project, as specified at §146.86(b)(5).EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility regarding the selection and use of cements for Class VI wells that are appropriate to the site-specific conditions of the project. With the permit application, the owner or operator must submit well construction procedures, as specified at §146.82 (a)(12), that demonstrate that the well as constructed will prevent unacceptable fluid movement; allow the use of appropriate testing devices and workovertools; and allow continuous monitoring of the annulus space between the injection tubing and longstring casing, as specified at §146.86(a). The Director will evaluate the procedures in the context of geological and proposed operating data about the site.

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.

Commenter Name: Tiffany Rau Letter ID: 0224 Commenter Organization: Hydrogen Energy International Comment ID: 21681 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: HEI strongly supports, with one modification discussed below, EPA’s actual language of the Proposed Rule in section 146.86(b)(5), which establishes a reliable performance standard that will achieve protection of USDWs. Section 146.86(b)(5) states, "Cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life the geologic sequestration project." HEI recommends that EPA’s discussion in the Preamble should be consistent with the actual language of the Proposed Rule to ensure clarity and remove any ambiguity regarding the performance-based approach set forth in the Proposed Rule.

Response: The final rule does not specifically require the use of acid-resistant cements, but it requires at §146.86(b)(5) that cement and cement additives be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life the GS project. Both field and laboratory studies have found acid alteration where traditional well cements have been used for CO2 injection. Although the laboratory and field studies suggest that corrosion problems may not be severe, such problems cannot be conclusively ruled out, and the amount of available data on this problem is still relatively small. Laboratory investigation of cement degradation is an ongoing research area, and field-based studies are very few. There also does not appear to be a clear consensus at this time on the corrosion risks for the steel components of injection wells. Given the anticipated long lifespan of a Class VI well and the difficulties that would be associated with a corrosion-related well failure, EPA believes that the construction requirements at §146.86 are justified.

EPA clarifies that the requirement at §146.86(b)(5) is that cement and cement additives must be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project.

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

Commenter Name: Brian Williams Letter ID: 0225 Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21730
Comment: (3) Specific Comments

In addition to the foregoing, BP respectfully submits the following areas of specific comment:

(i) Well Design and Construction To Avoid Corrosion

One area of comment requested by EPA relates to requirements for "degradation-resistant well construction materials, such as acid- resistant cements and corrosion resistant casing." (73 Fed. Reg. at 43510) Based upon historical industry experience and field studies, this would be an excessive requirement and not reasonably necessary to protect USDWs. Risk Profile of a CO2 Geological Storage Project: Wells, by Christopher, Crow, Dodds, Wright, Williams, March 2008.

BP strongly discourages EPA from setting a requirement to use degradationresistant materials & cement. Actual field observations based upon sampling of in situ casing and annular cements do not support this general requirement. The studies referenced by EPA in its Preamble exposed cement in a laboratory setting to a continuously-refreshed supply of CO2-saturated brine, which then reportedly caused the cement to degrade. (Duguid et al., 2004 and Kutchko et al., 2007.) These studies represent variations in cement alteration rates due to curing and exposure conditions, but neither supports the requirement for the use of degradation-resistant materials and cement because the laboratory procedures that were used do not necessarily represent the actual barrier exposure conditions in an appropriately cemented operating well. Indeed, the findings of Kutchko’s laboratory study suggested there would be limited degradation even after decades, which is consistent with the field study results of Carey et al.,

2007.

EPA’s rulemaking should give considerable weight to documented field surveys which provide more relevant well information, such as those conducted at the SACROC development in the Permian Basin (ref. Carey et al., 2007) and in Colorado (ref. Crow et al, and CO2 Capture Project, 2008). Both of these field studies identified that hydraulic isolation was maintained across the caprock, and the majority of cement reaction was localized to the area near the CO2 interval. Field results indicate it is the appropriate placement of cement, and not the type of cement, that is key to delivery of effective isolation and hence prevention of casing corrosion. Furthermore, cement placement to completely fill the annular space between borehole and casing is the primary means of achieving this objective.

Based on the foregoing, degradation-resistant materials should not be mandated for all projects, without regard to site-specific characteristics. Rather, the application of degradation-resistant materials & cement, if any, should bedefined on site-specific characteristics.

Response: The rule does not specify the materials and cements to be used; rather, it provides owners or operators with the flexibility to choose, as long as the cements are compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project, as specified at §146.86(b)(5).

EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility regarding the selection and use of cements for Class VI wells that are appropriate to the site-specific conditions of the project. With the permit application, the owner or operator must submit well construction procedures, as specified at §146.82 (a)(12), that demonstrate that the well as constructed will prevent unacceptable fluid movement; allow the use of appropriate testing devices and workovertools; and allow continuous monitoring of the annulus space between the injection tubing and longstring casing, as specified at §146.86(a). The Director will evaluate the procedures in the context of geological and proposed operating data about the site.

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.

Commenter Name: Brian Williams Letter ID: 0225 Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21731 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: BP strongly supports, with one modification discussed below, EPA’s actual language of the Proposed Rule in section 146.86(b)(5), which establishes a reliable performance standard that will achieve protection of USDWs. Section 146.86(b)(5) states, "Cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life the geologic sequestration project." BP recommends that EPA’s discussion in the Preamble should be consistent with the actual language of the Proposed Rule to ensure clarity and remove any ambiguity regarding the performance-based approach set forth in the Proposed Rule.

Response: The final rule does not specifically require the use of acid-resistant cements, but it requires at §146.86(b)(5) that cement and cement additives be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life the GS project. Both field and laboratory studies have found acid alteration where traditional well cements have been used for CO2 injection. Although the laboratory and field studies suggest that corrosion problems may not be severe, such problems cannot be conclusively ruled out, and the amount of available data on this problem is still relatively small. Laboratory investigation of cement degradation is an ongoing research area, and field-based studies are very few. There also does not appear to be a clear consensus at this time on the corrosion risks for the steel components of injection wells. Given the anticipated long lifespan of a Class VI well and the difficulties that would be associated with a corrosion-related well failure, EPA believes that the construction requirements at §146.86 are justified.EPA clarifies that the requirement at §146.86(b)(5) is that cement and cement additives must be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project.

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.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24038 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule: (5) Cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life the geologic sequestration project. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the
location of channels to ensure that USDWs are not

Schlumberger Suggested Revision: (5) Cement and cement additives must be
suitable for use with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the project life. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

Schlumberger Rationale: Well cements need to site and condition specific. There may be instances or places in the well that will require special cements. It is also that the cement in the well last as long as the project and post injection period.

Response: EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility regarding the selection and use of cements for Class VI wells that are appropriate to the site-specific conditions of the project. With the permit application, the owner or operator must submit well construction procedures, as specified at §146.82 (a)(12), that demonstrate that the well as constructed will prevent unacceptable fluid movement; allow the use of appropriate testing devices and workover tools; and allow continuous monitoring of the annulus space between the injection tubing and long-string casing, as specified at §146.86(a). The Director will evaluate the procedures in the context of geological and proposed operating data about the site. EPA adds that the rule does not specify cements to be used; rather, it provides owners or operators with the flexibility to choose, as long as the cements are compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project, as specified at §146.86(b)(5).

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.Commenter Name: Neeraj Gupta Letter ID: 0229 Commenter Organization: Battelle Energy Technology (BET) Comment ID: 21845 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: Page 82, Cement and Casing Materials- We suggest that if acid resistant cement and casing are to be required, they should be required only in the injection interval and immediate confining layer, which are most likely to be affected by the CO2 storage zone. The shallower drill strings may use more common materials. This seems a typical practice in most CO2 applications.

Response: EPA clarifies that acid-resistant cement and casing are not specifically required in a Class VI injection well. Rather, as stated in §146.86(b)(1), casings and cement used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards listed in the rule and be compatible with fluids with which the materials may be expected to come into contact. Therefore, some well materials may need to be acid-resistant and some may not if they do not come in contact with the CO2 stream or other corrosive fluids and if approved by the Director.

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.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23241 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: 19. EPA seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion resistant casing. EPA Notice 43510.

Based upon history in carbon dioxide injection projects, construction requirements should be based upon actual needs as identified in these projects and upon actual subsurface conditions. Industry experience with carbon dioxide EOR projects supports the use of conventional tubing, casing, and cements. These wells have been demonstrated to protect USDWs. Corrosion mitigation measures such as lined tubing, use of corrosion inhibitors, and proper dehydration of carbon dioxide provide adequate protection.

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 believes, however, that casings and cement and other materials used must have sufficientstrength and be designed for the life of the sequestration project. That is, corrosion mitigation measures, as suggested by the commenter, alone are not sufficient to protect USDWs. For this reason, the rule requires that materials meet standards established in the rule and be compatible with fluids with which the materials may be expected to come into contact.

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.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24900
Comment: Cannot measure the corrosiveness of the CO2 stream because it is not corrosive. Only liquids will yield pH measurements.

Response: EPA clarifies that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and described. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational information that the Director needs to determine appropriate standards for the tubing and packer. As written, the text at §146.86(c)(3)(ii) accounts for all characteristics of the CO2 that could affect the performance of the tubing and packer, including the chemical content, corrosiveness, temperature, and density.

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.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24905 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (5) Cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the geologic sequestration project. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

GWPC Recommendations: (5) Cement and cement additives must be suitable for use with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the operating life the well. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

Rationale: Experience with CO2 EOR under the class II program demonstrates the effectiveness of existing cementing materials and procedures. Standard API cements have been used in numerous CO2 EOR operations without adverseconsequences. Reference API CO2 EOR report and Carey et al. Bill Carey (SACROC) and Walter Crow (CCP2 - placement and annular gap more important than type).

Once the well is plugged, the plug will isolate the other portions of the well from the injected fluids.

Response: EPA clarifies that the requirement at §146.86(b)(5) is that cement and cement additives must be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project. 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.

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 measures that would be appropriate for the design of Class VI wells.

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 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.

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.

Commenter Name: Claire Olson Letter ID: 0260 Commenter Organization: Basin Electric Power Cooperative Comment ID: 22397 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: "3. Proposed Injection Well Construction Requirements"

EPA seeks comments regarding degradation resistant well construction materials, such as acid resistant cements and corrosion resistant casing. Dakota Gasification and Basin Electric agree with EPA's proposal to not specify materials and provide the owner/operator the flexibility to choose materials within the appropriate construction standards. The owner/operator working with the State Director should be in the best position to determine a cost effective strategy for construction, corrosion prevention, and corrosion monitoring that is best suited for the site conditions. For example, Dakota Gasification's CO2 pipeline and much of the Weyburn field systems are constructed from carbon steel, even though this is not common practice in acid gas systems. Due to someof the unique properties of this CO2 stream, the corrosion issues have been insignificant after 9 years of continuous service.

Response: EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility regarding appropriate materials for 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 the materials may be expected to come into contact and meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director, as provided at §146.86(b)(1).

EPA is aware of GS efforts at Weyburn; a paper summarizing EPA's review of Weyburn and other large international GS projects is in the rulemaking docket. 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: 0263 Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22805 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: III A. 3 Proposed Injection Well Construction Requirements

T. EPA seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion resistant casing.

IOGCC Response: Concerning degradation-resistant well construction materials, the EPA rule should not be overly prescriptive but instead set a performance standard that would allow on a case by case basis the cementing materials necessary to

meet the standard.

Response: EPA clarifies that corrosion-resistant materials are not specifically required in a Class VI injection well. Rather, as stated in §146.86(b)(1), casings and cement and other materials used must have sufficient strength and be designed for the life of the sequestration project. Further, materials must meet standards established in the rule and be compatible with fluids with which the materials may be expected to come into contact. EPA believes the rule provides an appropriate amount of flexibility. The construction requirements at §146.86 provide flexibility by listing the basic components a Class VI well must have to prevent endangerment of USDWs, and allow owners or operators to choose appropriate materials in meeting these requirements.

The Director will evaluate the appropriateness of the proposed well construction based on sitespecific information about the injection project, including injection pressures, injection and confining zone lithology, and information about the carbon dioxide stream as provided in §146.86(b)(1). In addition to the flexibility given to the owner and operator, Director's discretion is specifically provided in §146.86(b)(1) for casing and cementing and §146.86(c)(2 and 3) for tubing and packer location and type. 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.Commenter Name: Brian Williams Letter ID: 0507 Commenter Organization: BP Alternative Energy Comment ID: 21164 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: But first, with regard to well construction, and specifically around the points of corrosion resistant materials and cement. Based on industry experience and field studies, corrosion resistant materials should not be mandated for allprojects, and the requirement, if there is any, should be made on a sitespecific basis. Early field studies, in particular by the CO2 capture project, indicate that it is the appropriate placement of cement and not the type of cement that delivers isolation and prevents casing corrosion.

The choice of casing and cement materials should be selected based on planned well operating life, i.e. decades, and not on the ultimate duration of the storage program itself. The potential for longer term exposure of casing during storage, which might occur after injection has stopped, is mitigated by plugging
the static well with corrosion resistant material.

Response: The rule does not specify cements to be used; rather, it provides owners or operators with the flexibility to choose, as long as the cements are compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project, as specified at §146.86(b)(5).

EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility regarding the selection and use of cements for Class VI wells that are appropriate to the site-specific conditions of the project. With the permit application, the owner or operator must submit well construction procedures, as specified at §146.82 (a)(12), that demonstrate that the well as constructed will prevent unacceptable fluid movement; allow the use of appropriate testing devices and workovertools; and allow continuous monitoring of the annulus space between the injection tubing and longstring casing, as specified at §146.86(a). The Director will evaluate the procedures in the context of geological and proposed operating data about the site.

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 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 USDW 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.Commenter Name: Doug Louis Letter ID: 0530 Commenter Organization: Kansas Corporation Commission Comment ID: 25076
Comment: injection zone. KCC staff believes an exotic blend of CO2 resistant cement is not needed considering the proven record of CO2 EOR well construction history.

Response: As described above, EPA clarifies the final rule does not mandate the use of corrosion resistant cement; the requirement at §146.86(b)(5) is that cement and cement additives must be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project. It should be noted that in Carey et al. (2007), their research on the ER- CO2 injection well at SACROC was unable to determine whether CO2 in the presence of water, dry CO2, or a CO2-brine mixture had caused the cement alteration observed. In Crow et al. (2008), the well materials studied were from a production well producing from a natural CO2 deposit that also produced associated water, so well materials were presumably exposed to CO2 in the presence of water. Meyer (2007) acknowledges the Carey study found no loss of hydraulic integrity after 30 years, but also mentions the use of acid-resistant cements in wells used for acid gas injection and where brine is encountered.

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.

Commenter Name: Talib Syed Letter ID: 0537
Comment ID: 21476 Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)
Comment: So that is about it. I think you are headed in the right direction, but we've got to be careful on, you know, we are going to learn as we go along. We have got a lot of experience that EOR, 70% of the current CO2 injections are the Permian Basin in west Texas. Okay. We started CO2 flooding in west Texas in you know, in the `50's so we have got a lot of information on how to design the wells, what the problems are, but for geosequestration where you are just, you know, storing it in deep seated aquifers, you have got to be careful with the wells. You have got to be careful about you know, the reaction of the tubulars, the reaction on the cement. Again for EOR, if you got a cement like, let us say a problematic cement, that is not going to be effective in preventing flow. It has to be modified and there are now new cements that are coming in for specifically designed for CO2 purposes. So these types of cements may be effective again, but again we have got to watch out for each case and not just a sealed okay if it is there because KBR and Halliburton and all the other service companies are coming up with new cement specifically designed for making sure that in every instance you have got that area covered. Okay?

Response: EPA clarifies that the requirement at §146.86(b)(5) is that cement and cement additives must be compatible with the CO2 stream and formation fluids and of sufficient quality and quantityto maintain integrity over the design life of the GS project. EPA believes that the use of acidresistant cements is one of several protective measures for meeting that Class VI well construction requirement, along with the requirements for surface casing and long-string casing and well tubulars that are compatible with the CO2 and formation fluids. See the discussion of Class VI wellconstruction requirements in the preamble to the final GS rule for additional information.

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).

The Agency plans to, every six years, collect and review data on GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

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



### Individual Comments

Commenter Name: Michael H. Cochran Letter ID:

0108 Commenter Organization: Bureau of Water, Division of Environment, Kansas Department of Health & Environment (KDHE) Comment

ID: 21975
Comment: 146.87 (a)(2)(i): Need to also require a gamma log. This is an inexpensive log to conduct and provides good information on the type of formations encountered.

146.87 (a)(2)(ii): Should also allow the option of using cement evaluation logs, which may actually be superior to the cement bond log in many situations. The cement evaluation log provides a 360-degree map of the cement and can actually show the orientation and extent of channeling.

146.87 (a)(3)(ii): Again, should allow the option of using cement evaluation logs, which may actually be superior to the cement bond log in many situations. Also, should require an initial casing inspection log to establish baseline casing conditions, especially since corrosion is a concern in this type of well and then conduct periodic casing inspection logs to monitor corrosion. We do not see a need for the temperature log if the purpose is to determine the top of the cement. We do see some benefit to conducting the log to establish the baseline temperature gradient in the well.

146.87 (a)(4)(i): We recommend not allowing the use of a gas for conducting the annulus pressure test. Based on our experience, gas is not a sensitive test medium due to its significant compressibility. A liquid provides an extremely sensitive test because of its incompressibility and should be the fluid of choice for such an important test.

146.87 (b): The submittal of the cores to the Director is not practical and should not be a requirement. What the Director needs is the core report withthe test results. The operator should be required to first submit a coring plan to the Director listing the interval to be cored, the coring procedures, the tests to be conducted and proposed storage of the core for review and consideration of approval by the Director. A core report, including the test results and the geomechanical characteristics and values determined such as fracture gradient shall be submitted to the Director. The requirement for the core itself could be that the core shall be made available for inspection by the Director upon the request of the Director.

Response: Regarding the comment on §146.87(a)(2)(i), EPA believes that a gamma log will not always provide better information than resistivity and spontaneous potential logging. Gamma logs can provide information on the mineral composition of the formations, but do not provide the physical (lithologic and stratigraphic) information available from resistivity and spontaneous potential logs. Gamma logs also do not provide information on the formation fluids. EPA adds that if the Director determines that a gamma ray log will provide better information on the surface casing portion of the well, he/she has authority to require one.

Regarding the comment on §146.87(a)(2)(ii), EPA clarifies at §146.87(a)(2)(ii) that owners or operators must perform a cement bond (i.e., cement evaluation) log after the casing is set and

cemented.

Regarding the comment on §146.87(a)(4)(i), EPA disagrees that compressibility of gas would yield inaccurate readings for testing the annulus. Pressure testing by liquid or gas is a common practice. Compressibility or any other characteristics would be known and could be compensated for by calculation. EPA clarifies that pressure testing of the injection well (with liquid or gas) is to be performed during the construction phase, not during injection operations. Continuous recording of the annulus fluid pressure and volume during injection is required at §§146.88(e) and 146.89(b).

Regarding the comment on §146.87(b), EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

EPA has conducted extensive research and has found that the tests and logs specified at §146.87(a) have been proven in industry practice and research to identify cementing flaws. EPA adds that these tests are necessary to verify information about the injection and confining zones, and ensure that the well is being drilled and cased as approved and has mechanical integrity. This information demonstrates that the well can be operated and tested in a manner that will meet the requirements for Class VI wells. Should alternative methods be shown to provide equivalent or better information, the Director may allow such alternatives under §146.87(a)(5).

Commenter Name: Leslie Savage Letter ID: 0122 Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24788 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: (c) The owner or operator must record the fluid temperature, pH, conductivity, reservoir pressure and the static fluid level of the injection zone (s).Response: The text at §146.87(d) as written requires data on the injection zone and confining zone or zones. This is to ensure that, if the Director requires characterization of additional containment/confining zones (§146.83(b)), appropriate data are collected.

Commenter Name: Leslie Savage Letter ID: 0122 Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24789 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: (d) At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zone (s) :

Response: The text at §146.87(d) as written requires data on the injection zone and confining zone or zones. This is to ensure that, if the Director requires characterization of additional containment/confining zones (§146.83(b)), appropriate data are collected.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22547
Comment: During drilling and construction of the injection well, important, site-specific data must be collected to verify the facts included in the application, provide quantitative data for refinement of the ground-water model, and test the injectivity of the proposed injection zone. The testing currently recommended in the regulations during construction of Class I wells includes geophysical logs run during drilling, deviation checks to ensure that reamed holes do not deviate from pilot holes, leaving conduits in the formation, and logs to measure the integrity of the completed wells. The NGWA recommends the following testing during construction:

A. Identification of the lowermost USDW should be confirmed during drilling, using tests such as the following:

1. Sampling discharge from packer tests (straddle packers or single-packer bottom-hole test). 2. Cross plots of induction or resistivity with sonic/neutron/density porosity measurements and deduction of fluid resistivity using Archies Law (verification of porosity with core samples) 3. Bottom-hole water sampling during pilot hole drilling (with mud) 4. Depth sampling in pilot hole while pumping 5. Collection, logging, and archiving, of rock cores through the sealing and target formations.

B. The demonstration of confinement is the most critical task in construction of the well. Some information can be collected only prior to the installation of casing so careful consideration should be given to formation sampling before the well is completed. We recommend that borehole geophysical methods, such as, but not limited to, resistivity, neutron, gamma, and density logs, be combined with formation imaging such as, but not limited to, digital video and acoustic televiewer logging to specify lithologic units, geologic properties, and faults or fractures. Hydraulic testing such as straddle packerinjection can be completed prior to completion of the well. After completion, long-term pumping tests should be conducted over a sufficient time period to assure near-pseudo-steady state head conditions in the vicinity of the well. Interpretation of these data and tests should be used to refine the ground-water flow and transport model.

Response: EPA agrees there are numerous tests available to characterize subsurface formations, including identifying the lowermost USDW. The owner or operator must describe his or her proposed formation testing program as part of the permit application, pursuant to §146.82(a)(8). The Director will evaluate the proposed formation testing plan, along with site-specific geologic information, the AoR and corrective action plan, and proposed well construction procedures. If, based on a review of this information, the Director determines that additional logs and tests are necessary to provide assurance that USDWs will be protected from endangerment, he or she has authority at §146.87(a)(5) to require additional testing. EPA adds that during the permit application process, the owner or operator and the permitting authority will work together to determine which tests are appropriate, based on the site-specific circumstances.

EPA is developing guidance on monitoring and testing that will describe recommended tests andprocedures to assist owners/operators and Directors in evaluating the requirements for preoperational logging and testing under §146.87. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22604 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule: 146.87(a)(3)(ii)

Proposed revision: (ii) A cement bond, variable density log, and radial cement evaluation log and a temperature log after the casing is set and cemented.

Rationale: NGWA supports inclusion of a radial cement evaluation log in addition. The addition of this test will help identify any potential channels in the cement out from casing

Response: EPA clarifies at §146.87(a)(2)(ii) that owners or operators must perform a cement bond (i.e., cement evaluation) log after the casing is set and cemented.

Commenter Name: Christine Reimer Letter ID: 0142 Commenter Organization: National Ground Water Association Comment ID: 22605
Comment: Proposed Rule: 146.87(a)(4)

Comment: NGWA supports the inclusion of this series of tests.

Response: EPA acknowledges the comment and agrees that logging and testing requirements are appropriate and necessary. The requirements at §146.87 stem from existing knowledge and practices in place for other injection well classes and within the oil and gas industry, and are tailored to the special characteristics of CO2 injection for GS. The final rule retains the requirements fordemonstration of internal and external mechanical integrity required at §146.87(a)(4).

Commenter Name: James Dooley Letter ID: 0156 Commenter Organization: Joint Global Change Research Institute, Pacific Northwest National Laboratory Comment ID:

22675
Comment: - Page 43538. Does the USEPA (or states that have primacy for Class VI wells) really want to take physical possession of cores from prospective GS sites? The rule currently states "The owner or operator must take and submit to the Director whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s)." I understand the requirement that the Class VI permit applicant needs to take cores and needs to perform tests upon them but wouldn’t it be more meaningful for the "Director" to receive a written summary of those tests and a description of the methodologies used in the testing of the cores than to literally take physical possession of the cores themselves? The USEPA should consider rewording this

passage.

Response: EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24178 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)

API Comments: (a) During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic

formations to assureEVALUATE conformance with the injection well construction requirements under §146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, such logs and tests must include: THE DIRECTOR MAY REQUIRE

SUCH LOGS AND TESTS AS MAY BE NEEDED AFTER TAKING INTO ACCOUNT THE

AVAILABILITY OF SIMILAR DATA IN THE AREA OF THE DRILLING SITE, THE CONSTRUCTION PLAN,

AND THE

NEED FOR ADDITIONAL INFORMATION THAT MAY ARISE FROM TIME TO TIME AS

THE
CONSTRUCTION OF THE WELL PROGRESSES AND THESE MAY INCLUDE THE

FOLLOWING:Rationale: Obtaining the geologic information will not assure conformance with well construction requirements, just measure or evaluate it.

In well defined areas, these evaluations are frequently unnecessary. The Director should have discretion to select the appropriate requirements necessary to obtain sufficient baseline data and information. For example, in an area where a number of wells are being drilled, the logging of surface hole yields

little useful additional information.

In particular, this change would allow the Director to reduce the requirements when multiple wells are installed for a project.

Response: EPA believes that all logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. This information is needed to demonstrate that the well can be operated and tested in a manner that protects USDWs from endangerment. While the tests do provide information on some of the same items, each test provides unique pieces of information that build on each other and allow for interpretations not possible with a single test.

EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information, and the Director may accept information on cores of the injection and confining zones from nearby wells if the owner or operator can demonstrate that such cores are representative of conditions at the well in question and core retrieval is not possible, as specified at §146.87(b). EPA believes that logs and tests must be performed on each well drilled regardless of existing information about the area to account for the complexity of CO2 injection well construction and the buoyancy of CO2. Existing lithologic and geologic information may lack the details needed for site-specific well design and the geology needed to support protection of USDWs from endangerment.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 29190 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(2)(i)

API Comments: (i) Resistivity, spontaneous potential, and caliper logs before the casing is installed; and

Rationale: After a few wells are drilled in an area, these evaluations are frequently unnecessary and yield little new information. This is an example of where Director discretion may be appropriate.

Rule Provision: 146.87(a)(2)(ii)

API Comments: (ii) ACement bond and variable density log, and a temperature log evaluationlog(s) after the casing is set and cemented.

Rationale: Unusual to run these logs in a surface hole due to uniformity ofshallow geology. This is an example of where Director discretion may be appropriate.

The proposed change provides more flexibility to select the appropriate log to demonstrate adequate cement bond.

Rule Provision: 146.87(a)(3)(i)

API Comments: Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logsand any other logs the Director requires BASED ON SITE SPECIFIC CONDITIONS AND RISK-BASED FACTORS for the given geology before the casing is installed; and

Rationale: It is acceptable to specify basic logging requirements, however, special logs should not be specified. Any other information from the area should

be used instead.

Rule Provision: 146.87(a)(3)(ii)

API Comments: (ii) ACement bond and variable density log, and a temperature log EVALUATION LOG(S) after the casing is set and cemented.

Rationale: The proposed change provides more flexibility to select the appropriate log to demonstrate adequate cement bond.

Rule Provision: 146.87(a)(4)

API Comments: (4) A series of tests TEST(S) designed to demonstrate the internal and external mechanical integrity of injection wells, which may

include: (i) A pressure test with liquid or gas; (ii) A tracer surveyDIAGNOSTIC TOOLS such as oxygen-activation logging; (iii) A temperature or noise log; AND/OR (iv) A casing inspection log. if required by the Director; and

Rationale: Technical and grammatical corrections

In (iv), "if required by the Director" is unnecessary, as it is in subsection (a)

Rule Provision: 146.87(a)(5)

API Comments: (5) Any alternative methods that provide equivalent or better

information and that are required of and/or approved of by the Director.

Rationale: Same comment as above in (iv).

Rule Provision: 146.87(b)

API Comments: (b) The owner or operator must submit to the Director A REPORTDESCRIBING whole cores or sidewall cores REPRESENTATIVE of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept DATA FROM cores AND FLUID SAMPLES from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and

that such coresDATA are representative of conditions at the wellIN
THE WELLBORE. The Director may require the owner or operator to core other

formations in the borehole.

Rationale: The information required should be sufficient to properly describe the injection and confining zones.

Response: EPA believes that all logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. This information is needed to demonstrate that the well can be operated and tested in a manner that protects USDWs from endangerment. While the tests do provide information on some of the same items, each provides unique data that build on each other and allow for interpretations not possible with a single test.

EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information. EPA believes that logs and tests must be performed on each well drilled regardless of existing information about the area to account for the complexity of CO2 injection well construction and the buoyancy of CO2. Existing lithologic and geologic information may lack the details needed for site-specific well design and the geology needed to support protection of USDWs from endangerment.

EPA clarifies at §146.87(a)(2)(ii) and 146.87(a)(3)(ii) that owners or operators must perform a cement bond (i.e., cement evaluation) log after the casing is set and cemented.

Regarding the comment on §146.87(a)(4)(ii), EPA disagrees that allowing the use of unspecified "diagnostic tools" would provide the same amount of information as the requirement to perform a tracer survey. The track record for tracer surveys in evaluating mechanical integrity has been proven over time. EPA clarifies that a tracer survey is one of the mechanical integrity tests that may be required by the Director or used by the owner or operator. EPA agrees with the commenter about the wording of the casing inspection log requirement and made the suggested change to improve clarity. In the final regulation, §146.87(a)(iv) does not include the phrase, “if required by the Director.”

Regarding the comment on §146.87(b), EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 29200 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(c)API Comments: (c) PRIOR TO INJECTION WELL OPERATION, the owner or operator must

recordPROVIDE REPRESENTATIVE INFORMATION ON the fluidFORMATION temperature, FORMATION FLUID pH and conductivity, and reservoir pressure and
the static fluid level of the injection zone(s).

Rationale: Technical corrections. Reservoir pressure and static fluid level are redundant parameters.

The phrase "representative information" prevents the operator from having to do
all tests in all wells.

Rule Provision: 146.87(d)

API Comments: (d) At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zone(s): (1) Fracture pressure; (2) Other physical and chemical characteristics of the injection and confining zones; and (3) Physical and chemical characteristics of the formation fluids in the injection zone.

Rationale: With the exception of calculating fracture pressure, the requirements of this section appear redundant to other requirements of prior sections. The fracture pressure requirement has been added to section 146.87(e) below. (2) and (3) are too vague.

Rule Provision: 146.87(e)

API Comments: (e)(D) Upon completion butPrior to INJECTION WELL operation, the owner or operator must conduct the following tests to verify hydrogeologic characteristics of the injection zone: (1) A pump test; or (2) Injectivity tests.

ESTIMATE FRACTURE PRESSURES OF THE INJECTION AND CONFINING ZONES AND

INJECTIVITY

OF THE INJECTION ZONE. ESTIMATES SHOULD BE BASED ON REPRESENTATIVE

HYDROGEOLOGIC

AND GEOMECHANICAL CHARACTERISTICS OF THE INJECTION ZONE.

Rationale: Allows the use of information such as leak off tests conducted during the drilling operation.

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

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

Rule Provision: 146.87(f)API Comments: (f) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director 30 days prior to conducting the first testUPON SPUDDING THE WELL and NOTIFY THE

DIRECTOR OF submitany changes to the schedule 30 days 48 HOURS prior to

the nextscheduled test.

Rationale: The changes reflect the realities of flexible rig schedules and operations. In addition, they are fully consistent with current Class II requirements and practices which deal with these issues on a daily basis.

Response: EPA disagrees that "reservoir pressure" and "static fluid level" measurements required in §146.87(c) are redundant parameters. Although the static fluid level is equal to the bottom hole pressure, this may not always be identical to the reservoir pressure. Additionally, measuring the static fluid level provides additional assurance that the reading is accurate (or, provides the needed information in cases where a good reading is not obtained). In addition, a static fluid level measurement provides information regarding the proximity to USDWs that need protection afforded

to them.

EPA believes that the requirement to provide information on the injection and confining zones in §146.87(d) is warranted, and that the rule provides flexibility to account for the variety of geologic conditions that may be encountered at GS sites.

EPA clarifies that the owner or operator has the option of using pump tests or injectivity tests specified at §146.87(e) depending on which would provide the most valuable information based on site-specific conditions. Further, EPA disagrees that pump tests are irrelevant to determining injection zone properties. Depending on the characteristics or depth of knowledge of the confining and injection zone formations, pump tests may be necessary to prove that no hydraulic connection exists between the injection zone and a USDW. Additionally, EPA disagrees that the wording at §146.87(d) would lead the owner or operator to employ destructive testing methods for determination of fracture pressure. The wording "determined or calculated" allows for calculations to be performed
based on non-destructive methods.

EPA disagrees that the 30-day notification requirement is unreasonable. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide much needed field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ability to be involved.

Commenter Name: Robert J. Finley Letter ID: 0180 Commenter Organization: Illinois State Geological Survey Comment ID: 23631
Comment: 146.87

(a)(1)

This section requires deviation checks for holes developed by drilling and reaming. An exception needs to be included, if this provision is to be kept, for drilling of core followed by reaming. Core is often collected with a bit ODresulting in a 4-inch sample diameter; however, the hole being drilled may be larger than the core bit OD. Coring, usually in 30-foot or 60-foot increments, may be followed by reaming before returning to use of the full-diameter drilling bit. There is no need to run a deviation check after this type of reaming, but such would be a violation of the regulations if this section were not modified to exclude coring operations.

Response: EPA agrees that, in some cases, such as the situation mentioned by the commenter, a deviation check may not be necessary. EPA has modified the GS rule at §146.87(a)(8) to require the owner or operator to submit a pre-operational testing plan that meets the requirements of §146.87. EPA adds that the Director would have discretion to approve a plan without deviation checks that addresses circumstances where these tests may not be practical or useful, such as those mentioned by the commenter. EPA encourages owners or operators to discuss these situations with the Director when planning the deviation testing.

Commenter Name: Robert J. Finley Letter ID: 0180 Commenter Organization: Illinois State Geological Survey Comment ID: 23632
Comment: (a)(2)

It is unclear if it would be feasible to run all of these logs in surface casing. You have, perhaps, confused surface casing with intermediate casing. Surface casing often is only a few hundred feet in length and set to protect
near-surface USDWs. With fresh-water mud in the hole and fresh water in the formations, the spontaneous potential log is useless and will not provide the readings you expect, such as you might get from a natural gamma ray tool as an alternative. Further, the diameter of the hole may be such that a caliper log cannot give accurate readings, since the drilled hole may be 20 or 24 inches. What is written would logically apply to intermediate casing, but there is no

mention of such.

Response: EPA disagrees that the listed surface casing logging requirements would provide inaccurate readings. Because the surface casing runs through the lowermost USDW, it is imperative that the geology, lithology, and geochemistry of subsurface formations be defined and the integrity of the casing and cementing proven. EPA adds that this type of testing has been successfully performed on Class I hazardous wells. EPA adds that intermediate casings are not required for all Class VI wells; however, if a well were to be constructed with an intermediate casing, the Director has authority to require appropriate logging and testing, per §146.87(a)(5).

Commenter Name: Robert J. Finley Letter ID: 0180 Commenter Organization: Illinois State Geological Survey Comment ID: 23633
Comment: (b)

This reads that the operator should submit the actual whole or sidewall cores to the Director. Does the Director in every case have the staff and warehouse facilities to inventory, house, and curate these cores? It seems to me that what should be required to be submitted is any and all analyses of the core material and that the cores themselves should either be retained by the operator for a period of time and/or the operator should (subsequently) submit the cores to astate geological survey or the U.S. Geological Survey core storage facility. The operator could also contract with such a facility of house and curate the cores at the outset. Certainly, the actual cores should not be submitted to a regulatory authority with no provision for, or experience in, core curation.

Response: EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

Commenter Name: Robert J. Finley Letter ID: 0180 Commenter Organization: Illinois State Geological Survey Comment ID: 23634
Comment: (f)

These time requirements are not at all reasonable. Drilling and wellsite operations are by their nature changeable depending upon conditions that arise during drilling and upon availability of oil field service equipment. No operator can predict such activities 30 days in advance and likewise cannot predict schedule changes 30 days in advance. No more than 10 days notice shall be given for the advance schedule and changes must be allowable with 48 hours notice. Even 48 hours may not be doable in all situations for the operator, but it would be a reasonable compromise between notice time and operational considerations. If operators are required to report out-of-bounds conditions within 24 hours, regulators should be prepared to respond within a 10 day/48
hour framework.

Response: EPA disagrees that the 30-day notification requirement is unreasonable. The 30-day notification mirrors the current requirement for logging and testing of new Class I wells, as described in §146.66. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide much needed field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ability to be involved.

Commenter Name: Thomas Curtis Letter ID: 0181 Commenter Organization: American Water Works Association (AWWA) Comment ID: 23722 Other EPA Comment Codes and Descriptions: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 146.86)
Comment: Part 146.81(c) Specific benchmarks should be established to demonstrate that USDWs will not be endangered if the well is exempted from the casing and cementing requirements provided in Parts 146.86(b) and 146.87(a)(1) through (3). This will provide for a consistent application of this requirement across each permitting agency.

Response: EPA believes that, given the range of types of existing wells that may be candidates for conversion, flexibility is appropriate regarding conversion of Class I, II, or V wells for GS, provided
it can be demonstrated to the Director's satisfaction that the converted well can conduct Class VIoperations in a manner that does not endanger USDWs. The final GS rule, at §146.81(c), allows the construction of these wells to be grandfathered, 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 is developing guidance documents that will support UIC Directors in evaluating whether grandfathering specific wells is appropriate. For example, primacy guidance for primacy agencies will describe areas of Director’s discretion and recommended procedures and considerations for exercising that discretion. EPA is also developing guidance on construction of Class VI wells. The guidances will be available on EPA's web site at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Thomas Curtis Letter ID: 0181 Commenter Organization: American Water Works Association (AWWA) Comment ID: 23738 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Part 146.87(b) AWWA suggests that submittal of the cores to the Director is not very practical. The requirement should be rewritten to state that the Director should be provided with a summary report describing the cores and the test results. The operator should be required to first submit a coring plan to the Director listing the intervals to be cored, the coring procedures, the tests to be conducted and proposed storage of the core for review and consideration of approval by the Director. A core report, including the test results, geomechanical characteristics, and values calculated from the testing, such as fracture gradient, should be submitted to the Director. The owner/operator should make the cores available for inspection by the Director upon the request. AWWA recommends revising this part to read:

The owner or operator must submit to the Director a report describing whole cores or sidewall cores representative of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept data from cores and fluid samples from nearby wells if the owner or operator can demonstrate that such data are representative of conditions at the well. The Director may require the owner or operator to core other formations in the borehole to acquire more information on the subsurface geologic

characteristics.

Response: EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24343
Comment: D. Logging, Sampling and Testing Prior to Injection Well OperationWhile we have other specific concerns that are addressed in our detailed comments, our principal concern is that the logging, sampling and testing requirements of the proposed rule are overly rigid and prescriptive. In particular, the proposed rule appears to proceed from the premise that all of the information that could usefully be obtained from the logging, sampling and testing of a borehole should be obtained from the logging and testing of every borehole. Such an approach would be wasteful and unnecessarily burdensome.

Our concerns are particularly acute with respect to the formation sampling and testing requirements specified in proposed section 40 C.F.R. 146.87(b) and (d). While there are likely to be cases in which very little site-specific information is available prior to drilling, there will be other cases in which
vast amounts of information are or will be available and the incremental value of another exhaustive set of logs, samples and tests would be minimal. For example, extensive logging, sampling and testing clearly should not be necessary where there are multiple other injection wells or stratigraphic test wells that have been (or are being) used to gather the same kind of information for the same geologic formations and the same area. Accordingly, it is important to ensure that logging and testing requirements be tailored to the circumstances involved so that that costly and duplicative logging, sampling and testing requirements can be avoided.

Response: EPA believes that the logging and testing requirements in the GS rule are appropriate and necessary. The requirements at §146.87 stem from existing knowledge and practices in place for other injection well classes and within the oil and gas industry, and are tailored to the special characteristics of CO2 injection for GS.

EPA is developing guidance on monitoring and testing that will describe recommended tests andprocedures to assist owners/operators and Directors in evaluating the requirements for preoperational logging and testing under §146.87. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA clarifies that §146.87(b) provides some flexibility. EPA notes that §146.87(b) allows information on cores from nearby wells to be submitted if the owner or operator can demonstrate that core retrieval is not possible and that cores from nearby wells are representative of conditions at the Class VI well. EPA clarifies that, at a minimum, reports on cores of injection zones and confining zones, and samples of formation fluids must be submitted. Section 146.87(b) gives the Director authority to require the owner or operator to core other formations in the borehole if necessary to provide sufficient geologic information to verify that the site is suitable for GS.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24369 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 144.51(q)(1)

Proposed CCS Group Recommendations: (q) (1) The owner or operator of a Class I, II, III or VI well permitted under this part shall establish mechanical integrity prior to commencing injection or on a schedule determined by theDirector. Thereafter the owner or operator of Class I, II, and III wells must maintain mechanical integrity as defined in §146.8 and the owner or operator of Class VI wells must maintain mechanical integrity as defined in §146.89 of this chapter.

Basis for CCS Group Comments: EPA may want to reconsider the use of the term "or" as this implies that an initial MIT can be optional based on Directors discretion which contradicts 146.89 with respect to Class VI wells. Alternatively, the two provisions can be read together to require an initial MIT and to give the Director limited discretion to allow the scheduling of the initial MIT after some injection has occurred, such as may be required during initial testing of the well and injection zone.

Response: EPA disagrees that the suggested edit is needed, and clarifies that all owners or operators must demonstrate internal and external mechanical integrity prior to commencing injection as required at §146.87(a)(4).

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24453 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)

Proposed CCS Group Recommendations: (a) During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic formations to assureEVALUATE conformance with the injection well construction requirements under §146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, such logs and tests must include: THE DIRECTOR MAY REQUIRE SUCH LOGS AND TESTS AS MAY BE NEEDED AFTER TAKING INTO

ACCOUNT THE AVAILABILITY OF SIMILAR DATA IN THE AREA OF THE DRILLING SITE, THE

CONSTRUCTION PLAN, AND THE NEED FOR ADDITIONAL INFORMATION THAT MAY ARISE FROM

TIME TO TIME

AS THE CONSTRUCTION OF THE WELL PROGRESSES AND THESE MAY INCLUDE THE

FOLLOWING:

Basis for CCS Group Comments: Obtaining the geologic information will not assure conformance with well construction requirements, just measure or evaluate it.

In well defined areas, these evaluations are frequently unnecessary. The Director should have discretion to select the appropriate requirements necessary to obtain sufficient baseline data and information. For example, in an area where a number of wells are being drilled, the logging of surface hole yieldslittle useful additional information.

In particular, this change would allow the Director to reduce the requirements when multiple wells are installed for a project.

Response: EPA disagrees that the requirements for logs, surveys, and tests are unnecessary. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. This information is needed to demonstrate that the well can be operated and tested in a manner that protects USDWs from endangerment. While the tests do provide information on some of the same items, each test provides unique pieces of information that build on each other and allow for interpretations not possible with a single test.

EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information, and the Director may accept information on cores of the injection and confining zones from nearby wells if the owner or operator can demonstrate that such cores are representative of conditions at the well in question and core retrieval is not possible, as specified at §146.87(b). EPA believes that logs and tests must be performed on each well drilled regardless of existing information about the area to account for the complexity of CO2 injection well construction and the buoyancy of CO2. Existing lithologic and geologic information may lack the details needed for site-specific well design and the geology needed to support protection of USDWs from endangerment.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24454 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(1)

Proposed CCS Group Recommendations: Support the proposed language.

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

Response: EPA acknowledges the comment and agrees that logging and testing requirements are appropriate and necessary. The final rule retains the requirements for deviation checks at §146.87(a)(1).

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24455 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(2)(i)

Proposed CCS Group Recommendations: (i) Resistivity, spontaneous potential, and caliper logs before the casing is installed; and

Basis for CCS Group Comments: After a few wells are drilled in an area, these evaluations are frequently unnecessary and yield little new information. This isan example of where modification of requirements based on Director discretion may be appropriate.

Response: As described above, EPA disagrees that the requirements for logs, surveys, and tests are excessive or duplicative. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24456 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(2)(ii)

Proposed CCS Group Recommendations: (ii) ACement bond and variable density log, and a temperature log evaluation log(s) after the casing is set

and cemented.

Basis for CCS Group Comments: Unusual to run these logs in a surface hole due to uniformity of shallow geology. This is an example of where Director discretion may be appropriate.

The proposed change provides more flexibility to select the appropriate log to demonstrate adequate cement bond.

Response: EPA clarifies at §146.87(a)(2)(ii) that owners or operators must perform a cement bond (i.e., cement evaluation) log after the casing is set and cemented.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24457 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(3)

Proposed CCS Group Recommendations: Support the proposed language.

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

Response: EPA acknowledges the comment. The final rule retains the requirements for the logs required at §146.87(a)(3).

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24458 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(3)(i)Proposed CCS Group Recommendations: (i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs and any other logs the Director requires BASED ON SITE SPECIFIC CONDITIONS AND RISK-BASED FACTORS for the given geology before the casing is installed; and

Basis for CCS Group Comments: It is acceptable to specify basic logging requirements, however, special logs should not be specified. Any other

information from the area should be used instead.

Response: EPA believes that a minimum suite of logs and tests is necessary at all Class VI wells. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved and has mechanical integrity.

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

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

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24459 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(3)(ii)

Proposed CCS Group Recommendations: (ii) ACement bond and variable density log, and a temperature log EVALUATION LOG(S) after the casing is set

and cemented.

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

Response: EPA clarifies at 146.87(a)(3)(ii) that owners or operators must perform a cement bond (i.e., cement evaluation) log after the casing is set and cemented.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24460 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(4)

Proposed CCS Group Recommendations: (4) A series of tests TEST(S) designed to demonstrate the internal and external mechanical integrity of injectionwells, which may include: (i) A pressure test with liquid or gas; (ii) A tracer surveyDIAGNOSTIC TOOLS such as oxygen-activation logging; (iii) A temperature or noise log; AND/OR (iv) A casing inspection log. if required by the Director; and

Basis for CCS Group Comments: Technical and grammatical corrections in (4), (4) (ii) and (4)(iii). In (iv), "if required by the Director" is unnecessary.

Response: EPA disagrees that allowing the use of unspecified "diagnostic tools" would provide the same amount of information as the requirement to perform a tracer survey. The track record for tracer surveys in evaluating mechanical integrity has been proven over time. The Agency clarifies that a tracer survey is one of the mechanical integrity tests that may be required by the Director or used by the owner or operator.

EPA agrees with the commenter about the wording of the casing inspection log requirement at §146.87(a)(4) and made the suggested change to improve clarity. In the final regulation, §146.87(a)(iv) does not include the phrase, “if required by the Director.”

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24461 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(5)

Proposed CCS Group Recommendations: (5) Any alternative methods that provide equivalent or better information and that are required of and/or approved of by the Director.

Basis for CCS Group Comments: We interpret that (5) applies to 146.87(a) and support as proposed. For deletion, same comment as above in (iv).

Response: EPA retained the language in §146.87(a)(5) as proposed, allowing the Director discretion to authorize different methods in that provision, rather than moving such authority to 146.87(a), as the commenter requested. EPA notes that §146.87(a)(5) affords the Director discretion to approve alternative methods that provide equivalent or better information, and the Director may accept information on cores of the injection and confining zones from nearby wells if the owner or operator can demonstrate that such cores are representative of conditions at the well in question and core retrieval is not possible, as specified at §146.87(b).

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24462 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(b)

Proposed CCS Group Recommendations: (b) The owner or operator must submit to the
Director A REPORT DESCRIBING whole cores or sidewall cores REPRESENTATIVE of theinjection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept DATA FROM cores AND FLUID SAMPLES from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and thatsuch coresDATA are representative of conditions
at the wellIN THE WELLBORE. The Director may require the owner or operator to core other formations in the borehole.

Basis for CCS Group Comments: The information required should be sufficient to properly describe the injection and confining zones.

Response: EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24463 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(c)

Proposed CCS Group Recommendations: (c) PRIOR TO INJECTION WELL OPERATION,the
owner or operator must recordPROVIDE REPRESENTATIVE INFORMATION ON the

fluidFORMATION temperature, FORMATION FLUID pH and conductivity, and reservoir pressure and the static fluid level of the injection zone(s).

Basis for CCS Group Comments: Technical corrections. Reservoir pressure and static fluid level are redundant parameters. The phrase "representative information" prevents the operator from having to do all tests in all wells.

Response: EPA disagrees that "reservoir pressure" and "static fluid level" are redundant parameters. Although the static fluid level is equal to the bottom hole pressure, this may not always be identical to the reservoir pressure. Additionally, measuring the static fluid level provides additional assurance that the reading is accurate (or, provides the needed information in cases where a good reading is not obtained). In addition, a static fluid level measurement provides information regarding the proximity to USDWs that need protection afforded to them.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24464 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(d)

Proposed CCS Group Recommendations: (d) At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zone(s): (1) Fracture pressure; (2) Other physical and chemicalcharacteristics of the injection and confining zones; and (3) Physical and chemical characteristics of the formation fluids in the injection zone.

Basis for CCS Group Comments: With the exception of calculating fracture pressure, the requirements of this section appear redundant to other requirements of prior sections. The fracture pressure requirement has been added to section 146.87(e) below. (2) and (3) are too vague.

Response: EPA believes that the requirement to provide information on the injection and confining zones in §146.87(d) is warranted. As described above, the rule provides flexibility to account for the variety of geologic conditions that may be encountered at GS sites.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24465 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(e)

Proposed CCS Group Recommendations: e (D) Upon completion butPrior to INJECTION WELL operation, the owner or operator must

conduct the following tests to verify hydrogeologic characteristics of the injection zone: (1) A pump test; or (2) Injectivity tests.

ESTIMATE FRACTURE PRESSURES OF THE INJECTION AND CONFINING ZONES AND

INJECTIVITY

OF THE INJECTION ZONE. ESTIMATES SHOULD BE BASED ON REPRESENTATIVE

HYDROGEOLOGIC

AND GEOMECHANICAL CHARACTERISTICS OF THE INJECTION ZONE.

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

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

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

Response: EPA clarifies that the owner or operator has the option of using the pump tests or injectivity tests specified at §146.87(e) depending on which would provide the most valuable information based on site-specific conditions. Further, EPA disagrees that pump tests are irrelevant to determining injection zone properties. Depending on the characteristics or depth of knowledge of the confining and injection zone formations, pump tests may be necessary to prove that no hydraulic connection exists between the injection zone and a USDW.

EPA disagrees that the wording at §146.87(d) would lead the owner or operator to employ destructive testing methods for determination of fracture pressure. The wording "determined or calculated" allows for calculations to be performed based on non-destructive methods.Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24466 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(f)

Proposed CCS Group Recommendations: (f)(e) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director UPON SPUDDING THE WELL and submit any changes to the schedule 48 HOURS prior to the scheduled test.

Basis for CCS Group Comments: The changes reflect the realities of rig scheduling and are fully consistent with current Class II requirements and practices.

Response: EPA disagrees that the 30-day notification requirement is unreasonable. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide much needed field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ability to be involved.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24973 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(2)

Proposed CCS Group Recommendations: Support the proposed language.

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

Response: EPA acknowledges the comment; the final rule retains the requirements for logs to be run prior to installation of surface casing required at §146.87(a)(2).

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24681 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)

Anadarko Petroleum Corporation (APC) Comments: (a) During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic formations to assure conformance with the injection well construction requirements under §146.86, and to establishaccurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, such logs and tests must include: THE DIRECTOR MAY REQUIRE SUCH LOGS AND TESTS AS MAY BE NEEDED AFTER TAKING INTO

ACCOUNT THE AVAILABILITY OF SIMILAR DATA IN THE AREA OF THE DRILLING SITE, THE

CONSTRUCTION PLAN, AND THE NEED FOR ADDITIONAL INFORMATION THAT MAY ARISE FROM

TIME TO TIME

AS THE CONSTRUCTION OF THE WELL PROGRESSES AND THESE MAY INCLUDE THE

FOLLOWING:

Rationale: In well defined areas, these evaluations are frequently unnecessary. The director should have discretion to select the appropriate requirements necessary to ensure sufficient baseline data and information are available. For example, in an area where a number of wells are being drilled, the logging of surface hole yields little useful additional information. In particular, this change would allow the Director to reduce the requirements when multiple wells are installed for a project.

Response: EPA disagrees that the requirements for logs, surveys, and tests are unnecessary. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. This information is needed to demonstrate that the well can be operated and tested in a manner that protects USDWs from endangerment. While the tests do provide information on some of the same items, each test provides unique pieces of information that build on each other and allow for interpretations not possible with a single test.

EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information, and the Director may accept information on cores of the injection and confining zones from nearby wells if the owner or operator can demonstrate that such cores are representative of conditions at the well in question and core retrieval is not possible, as specified at §146.87(b). EPA believes that logs and tests must be performed on each well drilled regardless of existing information about the area to account for the complexity of CO2 injection well construction and the buoyancy of CO2. Existing lithologic and geologic information may lack the details needed for site-specific well design and the geology needed to support protection of USDWs from endangerment.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24682 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(2)(i)

Anadarko Petroleum Corporation (APC) Comments: (i) Resistivity, spontaneous potential, and caliper logs before the casing is installed; and

Rationale: After a few wells are drilled in an area, these evaluations arefrequently unnecessary and yield little new information. This is an example of where Director discretion may be appropriate.

Response: As described above, EPA disagrees that the requirements for logs, surveys, and tests are excessive or duplicative. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24683 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(2)(ii)

Anadarko Petroleum Corporation (APC) Comments: (ii) ACement bond and variable density log, and a temperature log evaluation log(s) after the casing

is set and cemented.

Rationale: Unusual to run these logs in a surface hole due to uniformity of shallow geology. This is an example of where Director discretion may be appropriate.

The proposed change provides more flexibility to select the appropriate log to demonstrate adequate cement bond.

Response: EPA clarifies at §146.87(a)(2)(ii) that owners or operators must perform a cement bond (i.e., cement evaluation) log after the casing is set and cemented.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24684 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(3)(i)

Anadarko Petroleum Corporation (APC) Comments: Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logsand any other logs the Director requires BASED ON SITE SPECIFIC CONDITIONS AND RISK-BASED FACTORS for the given geology before the casing is installed; and

Rationale: It is acceptable to specify basic logging requirements, however, special logs should not be specified. Any other information from the area should
be drawn on.

Response: EPA believes that a minimum suite of logs and tests is necessary at all Class VI wells. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved and has mechanical integrity.EPA notes that owners or operators will describe in their permit applications how they will construct and test the well, and will also submit site-specific information about the subsurface geology. The Director will evaluate the proposed logging activities along with site-specific geologic information to identify geologic data of interest.

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

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24685 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(3)(ii)

Anadarko Petroleum Corporation (APC) Comments: (ii) ACement bond and variable density log, and a temperature log EVALUATION LOG(S) after the casing

is set and cemented.

Rationale: The proposed change provides more flexibility to select the appropriate log to demonstrate adequate cement bond.

Response: EPA clarifies at 146.87(a)(3)(ii) that owners or operators must perform a cement bond (i.e., cement evaluation) log after the casing is set and cemented.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24686 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(a)(4)

Anadarko Petroleum Corporation (APC) Comments: (4) A series of tests TEST(S) designed to demonstrate the internal and external mechanical integrity of injection wells, which may include: (i) A pressure test with liquid or gas; (ii) A tracer surveyDIAGNOSTIC TOOLS such as oxygen-activation logging; (iii) A temperature or noise log; AND (iv) A casing inspection log. if required by the Director; and

Rationale: Technical and grammatical corrections

In (iv), "if required by the Director" is unnecessary.

Response: EPA disagrees that allowing the use of unspecified "diagnostic tools" would provide the same amount of information as the requirement to perform a tracer survey. The track record for tracer surveys in evaluating mechanical integrity has been proven over time. The Agency clarifiesthat a tracer survey is one of the mechanical integrity tests that may be required by the Director or used by the owner or operator.

EPA agrees with the commenter about the wording of the casing inspection log requirement at §146.87(a)(4) and made the suggested change to improve clarity. In the final regulation, §146.87(a)(iv) does not include the phrase, “if required by the Director.”

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24687 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(b)

Anadarko Petroleum Corporation (APC) Comments: (b) The owner or operator must
submit to the Director A REPORT DESCRIBING whole cores or sidewall cores REPRESENTATIVE of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept DATA from cores AND FLUID SAMPLES from nearby wells if the owner or operator can demonstrate that such DATA are representative of conditions in the wellbore.

Rationale: The information required should be sufficient to properly describe the injection and confining zones.

Response: EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24688 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(c)

Anadarko Petroleum Corporation (APC) Comments: (c) PRIOR TO INJECTION WELL OPERATION, the owner or operator must record the fluidFORMATION temperature, FORMATION FLUID pH and conductivity, and reservoir pressure and
the static fluid level of the injection zone(s).

Rationale: Technical corrections. Reservoir pressure and static fluid level are redundant parameters.

Response: EPA disagrees that "reservoir pressure" and "static fluid level" are redundant parameters. Although the static fluid level is equal to the bottom hole pressure, this may not always be identical to the reservoir pressure. Additionally, measuring the static fluid level provides additional assurance that the reading is accurate (or, provides the needed information in cases where a good reading is notobtained). In addition, a static fluid level measurement provides information regarding the proximity to USDWs that need protection afforded to them.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24689 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(d)

Anadarko Petroleum Corporation (APC) Comments: (d) At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zone(s): (1) Fracture pressure; (2) Other physical and chemical characteristics of the injection and confining zones; and (3) Physical and chemical characteristics of the formation fluids in the injection zone.

Rationale: With the exception of calculating fracture pressure, the requirements of this section appear redundant to other requirements of prior sections. The fracture pressure requirement has been added to section 146.87(e) below.

(2) and (3) are too vague.

Response: EPA believes that the requirement to provide information on the injection and confining zones in §146.87(d) is warranted, and that the rule provides flexibility to account for the variety of geologic conditions that may be encountered at GS sites.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24690 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(e)

Anadarko Petroleum Corporation (APC) Comments: (e)(D) Upon completion

butPrior to INJECTION WELL operation, the owner or operator must ESTIMATE
FRACTURE PRESSURES OF THE INJECTION AND CONFINING ZONES AND conduct the following tests to verify hydrogeologic AND GEOMECHANICAL characteristics of the injection zone, E.G., INJECTIVITY TESTS, ESTIMATES BASED ON OPEN-HOLE LOGGING TOOLS (E.G. MECHANICAL PROPERTIES LOGS), AND OTHER APPROPRIATE

METHODS. (1) A pump test; or (2) Injectivity tests.

Rationale: Allows the use of information such as leak off tests conducted during the drilling operation.

The results of a pump test (pumping fluid from the well) have no relevance foran injection well.

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

Response: EPA clarifies that the owner or operator has the option of using the pump tests or injectivity tests specified at §146.87(e) depending on which would provide the most valuable information based on site-specific conditions. Further, EPA disagrees that pump tests are irrelevant to determining injection zone properties. Depending on the characteristics or depth of knowledge of the confining and injection zone formations, pump tests may be necessary to prove that no hydraulic connection exists between the injection zone and a USDW.

EPA disagrees that the wording at §146.87(d) would lead the owner or operator to employ destructive testing methods for determination of fracture pressure. The wording "determined or calculated" allows for calculations to be performed based on non-destructive methods.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24691 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(f)

Anadarko Petroleum Corporation (APC) Comments: (f) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to

the Director 30 days prior to conducting the first testUPON SPUDDING THE WELL and submit any changes to the schedule 30 days 48 HOURS prior to the

nextscheduled test.

Rationale: The changes reflect the realities of flexible rig schedules and operations. In addition, they are fully consistent with current Class II requirements and practices, which deal with these issues on a daily basis.

Response: EPA disagrees that the 30-day notification requirement is unreasonable. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide much needed field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ability to be involved.

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24296
Comment: D. § 146.87 Logging, sampling, and testing prior to injection well operation.

EPA’s proposed § 146.87 delineates the information a permittee must collect during the drilling and construction of a Class VI well, prior to actual injection activities. Although the proposed rule generally allows the Director to approve alternative methods that provide equivalent or better information, it is not clear that the Director can utilize that regulatory flexibility to waiveunnecessary, duplicative testing which the proposed rule requires in several subparagraphs.

Response: EPA disagrees that any tests should be waived. EPA believes that all logs, surveys, and tests listed at §146.87 are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. This information is needed to demonstrate that the well can be operated and tested in a manner that protects USDWs from endangerment. While the tests do provide information on some of the same items, each test provides unique pieces of information that build on each other and allow for interpretations not possible with a single test. Existing lithologic and geologic information may lack the details needed for site-specific well design and the geology needed to support protection of USDWs from endangerment.

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24297 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: 1. EPA Proposed § 146.87 (a)(2) Before and upon installation of the surface casing:... (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented.

The requirements in §146.87(a)(2)(ii) to secure and submit specified logs before, upon and after surface casing installation is excessive. The proposed rule fails to provide a sufficient justification for requiring a cement bond and variable density log before and upon installation of the long string casing, and requiring a temperature log after the casing is set and cemented. Temperature logs are seldom used in the drilling industry to determine cement characteristics as they do not provide useful data regarding the bonding of cement. The rules should be modified to allow the permittee to select between the specified logs and any other logging tool approved by the Director as
follows:

§146.87(a)(2)(ii) A cement bond and variable density log OR OTHER APPROVED TOOL, and OR a temperature log after the casing is set and cemented. [see § 146.12(d)(2)(i)(B) Criteria and Standards applicable to Class I nonhazardous wells: Construction Requirements.]

*

*

* (5) Any alternative methods that provide equivalent or better information and that are required of and/or approved of by the Director.

THE DIRECTOR MAY WAIVE ANY LOG OR TEST SPECIFIED IN THIS SUBPARAGRAPH.

Response: Cement bond, variable density, and temperature logs are required by §146.87(a)(2) upon installation of the surface casing. EPA disagrees that the surface casing logging requirements are excessive. Evaluation of all logs, surveys, and tests listed in the rule will provide detailed information on the parts of the well that will penetrate the lowermost USDW and provide information on the quality of the cement seal with surrounding formations in order to ensureprotection of USDWs from endangerment.

As described above, EPA disagrees that any tests should be waived. While the tests do provide information on some of the same items, the tests provide unique pieces of information which enhance each other and allow for interpretations not possible with a single test. For example, a variable density log can detect microannuli, fractures, and formation effects. Temperature logs can detect fluid or gas flow through channels that cannot be detected by either of the other tests.

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24298 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: 2. EPA Proposed §146.87 (a)( (3) Before and upon installation of the long string casing: (i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any other logs the Director requires for the given geology before the casing is installed;

and

Once again, the proposed rule requires testing that would be of little benefit in protecting USDWs, but would impose significant costs on operators. For example, Denbury sees no basis to run a fracture finder log in every well. Fracture finder logs will only see minor fractures within the individual formations. The log does not provide information on whether these minor fractures can act as conduits between the injection zone and confining zone. To avoid unnecessary data collection and submittal, the rules should allow the applicant to propose and justify a logging suite based on the reservoir and geology associated with the particular CO2 project. The Director of course should be allowed to approve, or recommend revisions to the proposed suite. This would avoid mandating unneeded testing. Denbury suggests the following revised rule, incorporating this proposed change:

§146.87 (a)( (3) Before and upon installation of the long string casing: (i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any otherOR ANY SUITE OF LOGS

SUBMITTED BY THE PERMITTEE AND APPROVED BY logs the Director

BEFORE THE CASING IS INSTALLED requires forCONSIDERING the givengeology before the casing is installed ; and

Response: EPA believes that a minimum suite of logs and tests is necessary at all Class VI wells. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved and has mechanical integrity.

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

EPA adds that, should alternative methods be shown to provide equivalent or better information or ifsite-specific conditions and risk factors dictate that other logs are necessary, the Director has the discretion at §146.87(a)(5) to require further logs and tests if necessary and to approve alternative methods that provide equivalent or better information.

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24299 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: The proposed rule also requires unnecessary and duplicative logging with respect to the long-string casing.

3. EPA Proposed §146.87(a)( (3) Before and upon installation of the long string casing: (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented.

Denbury suggests that the logging options it recommends with respect to surface casing also apply for the long-string casing. Thus, the proposed rule should be revised as
follows:

§146.87(a)(3)(ii) A cement bond and variable density log OR OTHER APPROVED TOOL, and OR a temperature log after the casing is set and cemented. [see § 146.12(d)(2)(ii)(C) Criteria and Standards applicable to Class I nonhazardous wells: Construction Requirements.]

Response: EPA disagrees that the requirements for logging of the long-string casing at §146.87(a)(3)(ii) are unnecessary. While the tests do provide information on some of the same items, the tests provide unique pieces of information which enhance each other and allow for interpretations not possible with a single test. For example, a variable density log can detect microannuli, fractures, and formation effects. Temperature logs can detect fluid or gas flow through channels that cannot be detected by either of the other tests.

Determining the quality of the cementing of the long-string casing is essential to the protection of USDWs from endangerment. EPA adds that, should alternative methods be shown to provide equivalent or better information, the Director may allow such alternatives under §146.87(a)(5).

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24300 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: 4. EPA Proposed §146.87(b) The owner or operator must take and submit to the Director whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core other formations in the borehole.

Denbury opposes the requirement to collect cores from more than one (1) wellwithin a CO2 project. As a practical matter, the majority of the important physical and geophysical properties of the injection reservoir, including the particular attributes of the confining formations can and are required to be evaluated from logs and other scientific, reliable measures. A "whole core," as specified in §146.87(b) is only a very small sample of the attributes of a reservoir and a sidewall core, an even smaller sample. The former is very expensive to collect, and the latter often not available. Neither is essential given the vast amount of data otherwise required, and multiple samples, as proposed by the rule, are not reasonable. The unreasonableness of the whole core, sidewall core and extra core sampling is evident upon consideration of the sheer volume of physical evidence that this provision alone may produce. For example, in Texas there are over 5000 existing Class II CO2 injection wells. If a small fraction of these wells are converted to Class VI CO2 injection wells following the completion of production activities, there will be a large universe of cuttings. Where will the regulatory agency store this magnitude of cuttings? This may become a particular problem given the total number of CO2 sequestration projects that may be proposed.

Denbury suggests the following:

§146.87(b) AT THE SPECIFIC REQUEST OF THE DIRECTOR AND ONLY WHERE CORE RETRIEVAL IS POSSIBLE, TThe owner or operator must take and
submit to the Director A whole core s or sidewall core s of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core other formations in the

borehole.

Response: EPA clarifies that §146.87(b) allows information on cores from nearby wells to be submitted if the owner or operator can demonstrate that core retrieval is not possible and that cores from nearby wells are representative of conditions at the Class VI well. EPA clarifies that, at a minimum, reports on cores of injection zones, confining zones, and samples of formation fluids must be submitted. Section 146.87(b) gives the Director authority to require the owner or operator to core other formations in the borehole if necessary to provide sufficient geologic information to verify that
the site is suitable for GS.

EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24301
Comment: 5. EPA Proposed §146.87(d) At a minimum, the owner or operator must determine or calculate the following information concerning theinjection and confining zone(s): (1) Fracture pressure; (2) Other physical and chemical characteristics of the injection and confining zones; and (3) Physical and chemical characteristics of the formation fluids in the injection zone.

Subparagraph (d) of §146.87 provides permittees with a generic list of data that is required regarding the injection and confining zone. Fracture pressure is specified. Under the circumstances, fracture pressure should only be calculated, rather than "determined" as any determination based on techniques beyond mathematical calculation will require coring or perforation of the casing, potentially decreasing the mechanical integrity of the well and running directly counter to the objective of the proposed rules. With respect to other generic data EPA seeks regarding the injection and confining zones, the proposed rule does not to provide sufficient guidance to the permittee on the scope of data required on the formation fluids and reservoir zones. Denbury requests clarification and specifics both with respect to the nature and type of "physical and chemical characteristics" EPA expects a permittee to submit in response to the requirements of 146.87(d) (2) & (3).

Response: EPA disagrees that the wording at §146.87(d) would lead the owner or operator to employ destructive testing methods for determination of fracture pressure. The wording "determined or calculated" allows for calculations to be performed based on non-destructive methods. EPA is developing guidance on monitoring and testing that will describe recommended tests and procedures to assist owners/operators and Directors in evaluating the requirements for pre-operational logging and testing under §146.87, including providing information on the physical and chemical characteristics of the injection and confining zones. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24302 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: 6. EPA Proposed §146.87(f) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director 30 days prior to conducting the first test and submit any changes to the schedule 30 days prior to the next scheduled test.

The agency requires the submission of a proposed logging and testing schedule at least 30 days in advance of those proposed activities. Although a logging and testing schedule certainly can be designed 30 or more days in advance, the actual date that logging is performed is usually available only 24 to 48 hours in advance of actual logging operations. A mandatory 30 day notice is simply not practical for logging and testing. Denbury asks that notice requirements in this subpart be adjusted to take into account the practical limitations experienced routinely in field operations. Suggested revised language is set forth below.§146.87(f) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a PROPOSED schedule of such activities to the Director AT LEAST 30 days prior to conducting the first test and
submit NOTICE AT LEAST 24 HOURS IN ADVANCE OF THE CONDUCT OF ANY ACTUAL

LOGGING AND TESTING. any changes to the schedule 30 days prior to the

next scheduled test.

Response: EPA disagrees that the 30-day notification requirement is unreasonable. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide much needed field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ability to be involved.

Commenter Name: Edward Steadman Letter ID: 0220 Commenter Organization: The Energy and Environmental Research Center at the University of North Dakota Comment ID:

21635
Comment: Page 43538. § 146.87 Logging, sampling, and testing prior to injection well operation. "...the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic formations." Relevant geologic formations needs to be defined.

Page 43538. § 146.87 Logging, sampling, and testing prior to injection well operation. The coring requirements are too burdensome if applicable cores are already available in the vicinity of the project.

Page 43538. § 146.87 Logging, sampling, and testing prior to injection well operation. Given the complexity of scheduling various service companies and activities at a project location requiring a schedule of all logging and testing 30 days prior to the first test and submission of any changes to the schedule 30 days prior to the next scheduled test are pointless and oftentimes impractical.

Response: Regarding clarification of the term "relevant geologic formations," EPA expects that during the permit application process, the owner or operator and the permitting authority will work together to determine which formations should be studied, based on the site-specific circumstances.

EPA disagrees that the requirements for logs, surveys and tests are excessive. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved and has mechanical integrity.Reliance on existing lithologic and geologic information may not provide adequate details for sitespecific well design and geologic knowledge to support protection of USDWs from endangerment. EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information, and the Director may accept information on cores of the injection and confining zones from nearby wells if the owner or operator can demonstrate that such cores are representative of conditions at the well in question and core retrieval is not possible, as specified at §146.87(b).

EPA disagrees that the 30-day notification requirement is unreasonable. Acknowledging thedeveloping nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide much needed field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ability to be involved.

EPA is developing guidance on monitoring and testing that will describe recommended tests andprocedures to assist owners/operators and Directors in evaluating the requirements for preoperational logging and testing under §146.87. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23974
Comment: 5. § 146.87 Logging, sampling, and testing prior to injection well operation.

EPA’s proposed § 146.87 delineates the information a permittee must collect during the drilling and construction of a Class VI well, prior to actual injection activities. Although the proposed rule generally allows the Director to approve alternative methods that provide equivalent or better information, it is not clear that the Director can utilize that regulatory flexibility to waive unnecessary, duplicative testing which the proposed rule requires in several subparagraphs.

EPA Proposed § 146.87 (a)(2) Before and upon installation of the surface casing:... (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented.

The requirements in §146.87(a)(2)(ii) to secure and submit specified logs before, upon and after surface casing installation is excessive. The proposed rule fails to provide a sufficient justification for requiring a cement bond and variable density log before and upon installation of the long string casing, and requiring a temperature log after the casing is set and cemented. Temperature logs are seldom used in the drilling industry to determine cement characteristics as they do not provide useful data regarding the bonding of cement. The rules should be modified to allow the permittee to select between

Response: EPA disagrees that any tests should be waived. EPA believes that all logs, surveys, and tests listed at §146.87 are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. This information is needed to demonstrate that the well can be operated and tested in a manner that protects USDWs from endangerment. While the tests do provide information on some of the same items, each test provides unique pieces of information that build on each other and allow for interpretations not possible with a single test. Existing lithologic and geologic information may lack the details needed for site-specific well design and the geology needed to support protection of USDWs from endangerment.

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23975 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rulelanguage
Comment: cement. The rules should be modified to allow the permittee to select between the specified logs and any other logging tool approved by the Director as
follows:

§146.87(a)(2)(ii) A cement bond and variable density log OR OTHER APPROVED TOOL, and OR a temperature log after the casing is set and cemented. [see § 146.12(d)(2)(i)(B) CRITERIA AND STANDARDS APPLICABLE TO CLASS I NONHAZARDOUS WELLS: CONSTRUCTION REQUIREMENTS.]

*

*

* (5) Any alternative methods that provide equivalent or better information and that are required of and/or approved of by the Director.

THE DIRECTOR MAY WAIVE ANY LOG OR TEST SPECIFIED IN THIS SUBPARAGRAPH.

Response: Cement bond, variable density, and temperature logs are required by §146.87(a)(2) upon installation of the surface casing. EPA disagrees that the surface casing logging requirements are excessive. Evaluation of all logs, surveys, and tests listed in the rule will provide detailed information on the parts of the well that will penetrate the lowermost USDW and provide information on the quality of the cement seal with surrounding formations in order to ensure protection of USDWs from endangerment.

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23976
Comment: EPA Proposed §146.87 (a)( (3) Before and upon installation of the long string casing: (i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any other logs the Director requires for the given geology before the casing is installed;

and

Once again, the proposed rule requires testing that would be of little benefit in protecting USDWs, but would impose significant costs on operators. For example, TxCCSA sees no basis to run a fracture finder log in every well. Fracture finder logs will only see minor fractures within the individual formations. The log does not provide information on whether these minor fractures can act as conduits between the injection zone and confining zone. To avoid unnecessary data collection and submittal, the rules should allow the applicant to propose and justify a logging suite based on the reservoir and geology associated with the particular CO2 project. The Director of course should be allowed to approve, or recommend revisions to the proposed suite. This would avoid mandating unneeded testing. TxCCSA suggests the following revised rule, incorporating this proposed change:

§146.87 (a)( (3) Before and upon installation of the long string casing: (i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any otherOR ANY SUITE OF LOGS SUBMITTED

BY THE PERMITTEE AND APPROVED BY logs the Director BEFORE THE CASING

IS INSTALLED requires forCONSIDERING the givengeology beforethe casing is installed ; and

*

*

*

Response: EPA believes that a minimum suite of logs and tests is necessary at all Class VI wells. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved and has mechanical integrity.

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

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

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23977 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: The proposed rule also requires unnecessary and duplicative logging with respect to the long-string casing.

EPA Proposed §146.87(a)( (3) Before and upon installation of the long string casing: (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented.

TxCCSA suggests that the logging options it recommends with respect to surface casing also apply for the long-string casing. Thus, the proposed rule should be
revised as follows:

§146.87(a)(3)(ii) A cement bond and variable density log OR OTHER APPROVED TOOL, and OR a temperature log after the casing is set and cemented. [see § 146.12(d)(2)(ii)(C) CRITERIA AND STANDARDS APPLICABLE TO CLASS I NONHAZARDOUS WELLS: CONSTRUCTION REQUIREMENTS.]

Response: EPA disagrees that the requirements for logging of the long-string casing at §146.87(a)(3)(ii) are unnecessary. While the tests do provide information on some of the same items, the tests provide unique pieces of information which enhance each other and allow for interpretations not possible with a single test. For example, a variable density log can detect microannuli, fractures, and formation effects. Temperature logs can detect fluid or gas flow through channels that cannot be detected by either of the other tests.

Determining the quality of the cementing of the long-string casing is essential to the protection of USDWs from endangerment. EPA adds that should alternative methods be shown to provideequivalent or better information, the Director may allow such alternatives under §146.87(a)(5).

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23978
Comment: EPA Proposed §146.87(b) The owner or operator must take and submit to the Director whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core other formations in the borehole.

TxCCSA opposes the requirement to collect cores from more than one (1) well within a CO2 project. As a practical matter, the majority of the important physical and geophysical properties of the injection reservoir, including the particular attributes of the confining formations can and are required to be evaluated from logs and other scientific, reliable measures. A "whole core", as specified in §146.87(b) is only a very small sample of the attributes of a reservoir and a sidewall core, an even smaller sample. The former is very expensive to collect, and the latter often not available. Neither is essential given the vast amount of data otherwise required, and multiple samples, as proposed by the rule, is not reasonable. The unreasonableness of the whole core, sidewall core and extra core sampling is evident upon consideration of the sheer volume of physical evidence that this provision alone may produce. For example, in Texas there are over 5000 existing Class II CO2 injection wells. If a small fraction of these wells are converted to Class VI CO2 injection wells following the completion of production activities, there will be a large universe of cuttings. Where will the regulatory agency store this magnitude of cuttings? This may become a particular problem given the total number of CO2 sequestration projects that may be proposed.

Response: EPA clarifies that §146.87(b) allows information on cores from nearby wells to be submitted if the owner or operator can demonstrate that core retrieval is not possible and that cores from nearby wells are representative of conditions at the Class VI well. EPA clarifies that, at a minimum, reports on cores of injection zones, confining zones, and samples of formation fluids must be submitted. Section 146.87(b) gives the Director authority to require the owner or operator to core other formations in the borehole if necessary to provide sufficient geologic information to verify that
the site is suitable for GS.

EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23980Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: TxCCSA suggests the following:

§146.87(b) AT THE SPECIFIC REQUEST OF THE DIRECTOR AND ONLY WHERE CORE RETRIEVAL IS POSSIBLE, TThe owner or operator must take and submit
to the Director A whole core s or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core other formations in the

borehole.

Response: As described above, EPA clarifies that §146.87(b) allows information on cores from nearby wells to be submitted if the owner or operator can demonstrate that core retrieval is not possible and that cores from nearby wells are representative of conditions at the Class VI well. EPA clarifies that, at a minimum, reports on cores of injection zones, confining zones, and samples of formation fluids must be submitted. Section 146.87(b) gives the Director authority to require the owner or operator to core other formations in the borehole if necessary to provide sufficient geologic information to verify that the site is suitable for GS.

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23981
Comment: EPA Proposed §146.87(d) At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zone(s): (1) Fracture pressure; (2) Other physical and chemical characteristics of the injection and confining zones; and (3) Physical and chemical characteristics of the formation fluids in the injection zone.

Subparagraph (d) of §146.87 provides permittees with a generic list of data that is required regarding the injection and confining zone. Fracture pressure is specified. Under the circumstances, fracture pressure should only be calculated, rather than "determined" as any determination based on techniques beyond mathematical calculation will require coring or perforation of the casing, potentially decreasing the mechanical integrity of the well and running directly counter to the objective of the proposed rules.

With respect to other generic data EPA seeks regarding the injection and confining zones, the proposed rule does not to provide sufficient guidance to the permittee on the scope of data required on the formation fluids and reservoir zones. TxCCSA requests clarification and specifics both with respect to the nature and type of "physical and chemical characteristics" EPA expects a permittee to submit in response to the requirements of 146.87(d) (2) & (3).

Response: EPA disagrees that the wording at §146.87(d) would lead the owner or operator toemploy destructive testing methods for determination of fracture pressure. The wording "determined or calculated" allows for calculations to be performed based on non-destructive methods. EPA is developing guidance on monitoring and testing that will describe recommended tests and procedures to assist owners/operators and Directors in evaluating the requirements for pre-operational logging and testing under §146.87, including providing information on the physical and chemical characteristics of the injection and confining zones. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23982 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposed §146.87(f) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director 30 days prior to conducting the first test and submit any changes to the schedule 30 days prior to the next scheduled test.

The agency requires the submission of a proposed logging and testing schedule at least 30 days in advance of those proposed activities. Although a logging and testing schedule certainly can be designed 30 or more days in advance, the actual date that logging is performed is usually available only 24 to 48 hours in advance of actual logging operations. A mandatory 30 day notice is simply not practical for logging and testing.

TxCCSA asks that notice requirements in this subpart be adjusted to take into account the practical limitations experienced routinely in field operations. Suggested revised language is set forth below.

§146.87(f) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a PROPOSED schedule of such activities to the Director AT LEAST 30 days prior to conducting the first test and
submit NOTICE AT LEAST 24 HOURS IN ADVANCE OF THE CONDUCT OF ANY ACTUAL

LOGGING AND TESTING. any changes to the schedule 30 days prior to the

next scheduled test.

Response: EPA disagrees that the 30-day notification requirement is unreasonable. The 30-day notification mirrors the current requirement for logging and testing of new Class I wells, as described in §146.66. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide much needed field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ability to be involved.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24039 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule languageComment: §146.87 Logging, sampling, and testing prior to injection well operation.

Proposed Rule: (a) During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic formations to assure conformance with the injection well construction requirements under §146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, such logs and tests must include:

Schlumberger Suggested Revision: (a) During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic formations to assure conformance with the injection well construction requirements under §146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. The Director may require such logs and tests as may be needed after taking into account the availability of similar data in the area of the drilling site to ensure that the data is equivalent to the data as would be collected based on such logs and tests as::

Schlumberger Rationale: In well defined areas, these evaluations are frequently unnecessary. The director should have discretion to select the appropriate requirements necessary to ensure that sufficient baseline data and information are available. For example, in an area where a number of wells are being drilled, the logging of surface hole yields little useful additional

information.

Response: EPA disagrees that the requirements for logs, surveys, and tests are unnecessary. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. This information is needed to demonstrate that the well can be operated and tested in a manner that protects USDWs from endangerment. While the tests do provide information on some of the same items, each test provides unique pieces of information that build on each other and allow for interpretations not possible with a single test.

EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information. EPA believes that logs and tests must be performed on each well drilled regardless of existing information about the area to account for the complexity of CO2 injection well construction and the buoyancy of CO2. Existing lithologic and geologic information may lack the details needed for site-specific well design and the geology needed to support protection of USDWs from endangerment.Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24040 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule: (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented.

Schlumberger Suggested Revision: (ii) Cement evaluation logs after the casing is set and cemented to evaluate cement quality radially with sufficient resolution to identify channels or changes to the cement quality.

Schlumberger Rationale: Radial is key to finding pathways but the resolution must be sufficient to see the pathways. See the pathway identified in Crow et al

Response: EPA agrees with the suggested change. In the final GS rule, §146.87(a)(2)(ii) reads as follows: "A cement bond and variable density log to evaluate cement quality radially, and a temperature log after the casing is set and cemented."

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24041 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule: (4) A series of tests designed to demonstrate the internal and external mechanical integrity of injection wells, which may include:

Schlumberger Suggested Revision: (4) Test(s) designed to demonstrate the internal and external mechanical integrity of injection wells, which may

include:

Schlumberger Rationale: -

Response: EPA disagrees that the suggested edit is necessary, and the final rule retains the text as proposed.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24042 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule: (ii) A tracer survey such as oxygen-activation logging;

Schlumberger Suggested Revision: (ii) Diagnostic tools such as oxygenactivation logging;

Schlumberger Rationale: Technical correction

Response: EPA disagrees that the allowing the use of unspecified "diagnostic tools" would provide the same amount of information as the requirement to perform a tracer survey. The track record for tracer surveys in evaluating mechanical integrity has been proven over time. The Agency clarifiesthat a tracer survey is one of the mechanical integrity tests that may be required by the Director or used by the owner or operator.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24043
Comment: Proposed Rule: (5) Any alternative methods that provide equivalent or better information and that are required of and/or approved of by the Director.

Schlumberger Suggested Revision: -

Schlumberger Rationale: We interpret that (5) applies to 146.87(a)

Response: EPA clarifies that the Director has the discretion at §146.87(a)(5) to approve alternative logging, sampling, and testing methods that provide equivalent or better information than those specified in §146.87(a)(1-4). The Director may not allow MIT methods that have not been approved by EPA, pursuant to §146.89(e).

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24044 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule: (b) The owner or operator must take and submit to the Director whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core other

formations in the borehole.

Schlumberger Suggested Revision: (b) The owner or operator must submit to the Director a report describing whole cores or sidewall cores representative of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept data from cores and fluid samples from nearby wells if the owner or operator can demonstrate that such data are representative of conditions at the well.

Schlumberger Rationale: The information required should be sufficient to properly describe the injection and confining zones.

Response: EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

EPA clarifies that §146.87(b) allows information on cores from nearby wells to be submitted only if the operator can demonstrate that core retrieval is not possible and that cores from nearby wells arerepresentative of conditions at the Class VI well. If the Director approves the use of alternate cores and determines that additional logs, such as video logs, are necessary to evaluate the site, he/she has authority under §146.87(a)(5) to require additional information.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24045 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule: (c) The owner or operator must record the fluid temperature, pH, conductivity, reservoir pressure and the static fluid level of the injection zone(s).

Schlumberger Suggested Revision: (c) Prior to injection well operation, the owner or operator must record the formation temperature, formation fluid pH and conductivity, and reservoir pressure of the injection zone(s).

Schlumberger Rationale: -

Response: EPA clarifies that all logging, sampling and testing for characteristics of the injection zone required in §146.87 are, as defined in the title to that section, to be performed prior to injection well operation. EPA adds that §146.82(c)(7) requires that the Director evaluate the results of all logging and testing prior to authorizing injection.

Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24047 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule:(f) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director 30 days prior to conducting the first test and submit any changes to the schedule 30 days prior to the next scheduled test.

Schlumberger Suggested Revision: (f) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director upon spudding the well and submit any changes to the schedule 48 hours prior to the scheduled test.

Schlumberger Rationale: The changes reflect the realities of flexible rig schedules and consistency with Class II practices.

Response: EPA disagrees that the 30-day notification requirement is unreasonable. The 30-day notification mirrors the current requirement for logging and testing of new Class I wells, as described in §146.66. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide much needed field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ability to be involved.Commenter Name: Andrew Duguid Letter ID: 0226 Commenter Organization: Schlumberger Carbon Services Comment ID: 24049 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Proposed Rule: (e) Upon completion, but prior to operation, the owner or operator must conduct the following tests to verify hydrogeologic characteristics of the injection zone:

Schlumberger Suggested Revision: (d) At any time prior to injection well operation, the owner or operator must determine fracture pressures of the injection and confining zones and conduct tests to verify hydrogeologic and geomechanical characteristics of the injection zone, e.g.:

Schlumberger Rationale: -

Response: EPA disagrees that the suggested edit is necessary, and the final rule retains the text as proposed.

Commenter Name: Pamela A. Lacey Letter ID: 0228 Commenter Organization: American Gas Association Comment ID: 21805 Other EPA Comment Codes and Descriptions: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 146.86)
Comment: - Ensure Collaborative Process for GS Construction in Gas Storage Fields: Gas storage operators have particular expertise regarding their natural gas storage fields, and can help prevent problems if EPA helps to ensure their participation in the process of the site evaluation and construction of GS wells in natural gas storage fields. We ask you to revise sections 146.86 and 146.87 so as to authorize the Director to ensure the coordination between gas storage operators and GS well owners/operators in circumstances where the GS construction will occur in natural gas storage fields. Such coordination can involve, for example, obtaining input from the gas storage operators on the unique circumstances associated with the gas storage field where the GS well will be constructed. To assist in this process, gas storage field operators should have ready access to GS well records, well logs and cementing records for any GS construction activity that occurs in a gas storage field.

Response: EPA agrees that GS owners and operators and gas storage operators should coordinate when deciding where to locate their facilities. EPA expects that the permitting authority will be involved in this decision during the permit application process and when approving the permit. The permit application requires at §146.82(a)(2) that owners or operators submit a map showing all injection wells, which would include wells used for gas storage. The permitting process also requires at 124.10(c)(1)(xi) the notification of the state oil and gas agency and state mineral recovery agency, among others, when the draft permit is available for comment. The draft permit will also include the permit application. EPA believes that those agencies that should be involved in the decision will be properly informed under the final rule application and notification procedures.

Commenter Name: Philip Papadeas Letter ID: 0238Commenter Organization: Sandia Technologies, LLC Comment ID: 23353
Comment: §146.87 (f) Re: 30-day testing notification The requirements for 30-day notification should remain as such, the nature of drilling, workover, and testing is such that notification will not cover all testing. EPA or Agency notification of testing requirements, representative can witness the testing or be sent the data electronically with a summary for review, evaluation and concurrence.

Response: EPA acknowledges the comment; the final rule retains this provision.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23291
Comment: 146.87(a) Relevant geologic formations is too broad. This information should only be required for the injection and confining zones and possibly the next porous and permeable zone above the upper confining zone.

Response: Regarding clarification of the term "relevant geologic formations," EPA expects that during the permit application process, the owner or operator and the permitting authority will work together to determine which formations should be studied, based on the site-specific circumstances.

EPA is developing guidance on monitoring and testing that will describe recommended tests andprocedures to assist owners/operators and Directors in evaluating the requirements for preoperational logging and testing under §146.87. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23292
Comment: 146.87(a)2 Open hole logs in the surface hole are unusual and not necessary. If required, certainly not in every well in a project.

Response: Many types of logs (e.g., potential logs) cannot be run in a cased hole. Because the borehole for the surface casing runs through the lowermost USDW, it is imperative that the geology, lithology, and geochemistry of subsurface formations be defined. EPA adds that this type of testing has been successfully performed on Class I hazardous wells. EPA acknowledges that, while use of these logs may be unusual in oil and gas fields with a lot of data, it would be essential to identify these shallow USDWs or other zones in areas where Class VI wells could be drilled. Running caliper logs in surface holes also established a benchmark for determining adequate cement to be placed in
the well.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23293
Comment: 146.87(a)3 Should specify basic logging requirement not specific logs.

Response: EPA has conducted extensive research and has found that the tests and logs specified at §146.87(a) have been proven in industry practice and research to identify cementing flaws. EPA adds that these tests are necessary to verify information about the injection and confining zones, and ensure that the well is being drilled and cased as approved and has mechanical integrity. Thisinformation demonstrates that the well can be operated and tested in a manner that will meet the requirements for Class VI wells. Should alternative methods be shown to provide equivalent or better information, the Director may allow such alternatives under §146.87(a)(5).

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23294
Comment: 146.87(b) Coring should not be required if an adequate core and report exists for a nearby well. Coring should only be required of the injection and confining zones and possibly the next porous and permeable zone above the upper confining zone.

Response: EPA clarifies that §146.87(b) allows information on cores from nearby wells to be submitted if the owner or operator can demonstrate that core retrieval is not possible and that cores from nearby wells are representative of conditions at the Class VI well.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23295
Comment: 146.87(d)2 Vague and ambiguous.

Response: EPA believes that flexibility on this requirement is warranted to account for the variety of geologic conditions that may be encountered at GS sites. The owner or operator must describe in the permit application, pursuant to §146.82(a)(8) the proposed formation testing program, including how he or she would meet the requirements of §146.87(d). The Director will evaluate the proposed formation testing plan, along with site-specific geologic and geochemical information. EPA is developing guidance on monitoring and testing that will describe recommended tests and procedures to assist owners/operators and Directors in evaluating the requirements for pre-operational logging and testing under §146.87. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23296
Comment: 146.87(f) Unrealistic time frame. Tie initial reporting to spud date and 48

hour notification thereafter.

Response: EPA disagrees that the 30-day notification requirement is unreasonable. The 30-day notification mirrors the current requirement for logging and testing of new Class I wells, as described in §146.66. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide much needed field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ability to be involved.

Commenter Name: Kurt Waltzer Letter ID: 0250 Commenter Organization: Clean Air Task Force Comment ID: 22316
Comment: Cement bond logs and other outdated methods are not sufficient for establishing cement quality and integrity

Some of the techniques listed in §146.87(a)(2)(ii) and §146.87(a)(3)(ii), suchas cement bond and variable density logs are no longer state-of-the-art, and do not reveal the nature or shape of any voids in the cement - instead they represents an average estimate of void space. To verify the integrity of cement behind casings, including the location of any channels, contamination or missing cement, the Director should require "a cement map that incorporates data from a cement bond log, a variable density display, and an ultrasonic image, unless an alternative evaluation based on equivalent or better technologies has been approved in writing".

Response: EPA has conducted extensive research and has found that the tests and logs specified at §146.87(a)(2 and 3) have been proven through industry practice and research to identify cementing flaws. EPA also believes that the required logs are sufficient to show potential pathways for migration of fluid into and out of the wellbore. EPA adds that should alternative methods be shown to provide equivalent or better information, the Director may allow such alternatives under §146.87(a)(5). The Agency plans to, every six years, collect and review data on GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24847 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 144.51

EPA Proposal: 8. Section 144.51 is amended by revising the first sentence in paragraph (q)(1) and the first sentence in paragraph (q)(2) to read as follows:

§ 144.51 Conditions applicable to all permits.

* * * * *

(q) * * *

(1) The owner or operator of a Class I, II, III or VI well permitted under this part shall establish mechanical integrity prior to commencing injection or on a schedule determined by the Director. Thereafter the owner or operator of Class I, II, and III wells must maintain mechanical integrity as defined in § 146.8 and the owner or operator of Class VI wells must maintain mechanical integrity as defined in § 146.89 of this chapter. * * *

GWPC Recommendations: (q) * * *

(1) The owner or operator of a Class I, II, III or VI well permitted under this part shall establish mechanical integrity prior to commencing injection or on a schedule determined by the Director. Thereafter the owner or operator of Class I, II, and III wells must maintain mechanical integrity as defined in §146.8 and the owner or operator of Class VI wells must maintain mechanical integrity as defined in §146.89 of this chapter.Rationale: EPA may want to reconsider the use of the term "or" as this implies that an initial MIT can be optional based on Directors discretion which contradicts 146.89 with respect to Class VI wells. Alternatively, the two provisions can be read together to require an initial MIT and to give the Director limited discretion to allow the scheduling of the initial MIT after some injection has occurred, such as may be required during initial testing of the well and injection zone.

Response: EPA disagrees that the suggested edit is needed, and clarifies that all owners or operators must demonstrate internal and external mechanical integrity prior to commencing injection as required at §146.87(a)(4).

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29176 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87

EPA Proposal: 7. Logging, sampling, and testing prior to injection well operation

(a) During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic formations to assure conformance with the injection well construction requirements under § 146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, such logs and tests must

include:

GWPC Recommendations: (a) During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic formations to assure conformance with the injection well construction requirements under §146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. The Director may require such logs and tests as may be needed after taking into account the availability of similar data in the area of the drilling site, the construction plan, and the need for additional information that may arise from time to time as the construction of the well progresses and these may include the following:

Rationale: In well defined areas, these evaluations are frequently unnecessary. The director should have discretion to select the appropriate requirementsnecessary to ensure sufficient baseline data and information are available. For example, in an area where a number of wells are being drilled, the logging of surface hole yields little useful additional information.

In particular, this change would allow the Director to reduce the requirements when multiple wells are installed for a project.

Response: EPA believes that the logging and testing requirements in the GS rule are appropriate and necessary. The requirements at §146.87 stem from existing knowledge and practices in place for other injection well classes and within the oil and gas industry, and are tailored to the special characteristics of CO2 injection for GS.

EPA is developing guidance on monitoring and testing that will describe recommended tests andprocedures to assist owners/operators and Directors in evaluating the requirements for preoperational logging and testing under §146.87. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA clarifies that §146.87(b) provides some flexibility. EPA notes that §146.87(b) allows information on cores from nearby wells to be submitted if the owner or operator can demonstrate that core retrieval is not possible and that cores from nearby wells are representative of conditions at the GS well. EPA clarifies that, at a minimum, reports on cores of injection zones and confining zones, and samples of formation fluids must be submitted. Section 146.87(b) gives the Director authority to require the owner or operator to core other formations in the borehole if necessary to provide sufficient geologic information to verify that the site is suitable for GS.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29177 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (1) Deviation checks during drilling on all holes constructed by drilling a pilot hole which are enlarged by reaming or another method. Such checks must be at sufficiently frequent intervals to determine the location of
the borehole and to assure that vertical avenues for fluid movement in the form of diverging holes are not created during drilling; and

GWPC Recommendations: Support the proposed EPA language.

Rationale: Agree with EPA’s rationale.

Response: EPA acknowledges the comment; the final rule retains the requirements for deviation checks required at §146.87(a)(1). EPA adds that the Director would have discretion to approve a plan without deviation checks that addresses circumstances where these tests may not be practical or useful, such as those mentioned by the commenter. EPA encourages owners or operators to discuss these situations with the Director when planning the deviation testing.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29178 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rulelanguage
Comment: Rule Provision: 146.87(a)

EPA Proposal: (2) Before and upon installation of the surface casing:

GWPC Recommendations: Support the proposed EPA language.

Rationale: Agree with EPA’s rationale.

Response: EPA acknowledges the comment; the final rule retains the requirements for logging and testing prior to and upon installation of surface casing.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29179 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (i) Resistivity, spontaneous potential, and caliper logs before the casing is installed; and

GWPC Recommendations: (i) Resistivity, spontaneous potential, and caliper logs before the casing is installed; and

Rationale: After a few wells are drilled in an area, these evaluations are frequently unnecessary and yield little new information.This is an example of why it is appropriate to make this a discretionary rather than mandatory requirement. The proposed revision to 146.87(a) would give the Director the necessary discretion.

Response: EPA disagrees that the requirements for logs, surveys, and tests are excessive or duplicative. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29180 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented.

GWPC Recommendations: (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented.

Rationale: Unusual to run these logs in a surface hole due to uniformity of shallow geology. This is an example of why it is appropriate to make this a discretionary rather than mandatory requirement. The proposed revision to 146.87(a) would give the Director the necessary discretion.Response: As described above, EPA disagrees that the requirements for logs, surveys, and tests are excessive or duplicative. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information.

EPA clarifies that in the final GS rule, §146.87(a)(2)(ii) reads as follows: "A cement bond and variable density log to evaluate cement quality radially, and a temperature log after the casing is set

and cemented."

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29181 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (3) Before and upon installation of the long string casing:

GWPC Recommendations: Support the proposed EPA language.

Rationale: Agree with EPA’s rationale.

Response: EPA acknowledges the comment; the final rule retains the requirements for logging and testing prior to and upon installation of the long string casing.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29182 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any other logs the Director requires for the given geology before the casing is installed; and

GWPC Recommendations: Support the proposed EPA language.

Response: EPA acknowledges the comment; the final rule retains the requirements for the logs and tests required at §146.87(a)(3).

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29183 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented.

GWPC Recommendations: (ii) Cement evaluation logs after the casing is set and cemented to evaluate cement quality with sufficient radial resolution to identify channels or missing cement.Rationale: Acceptable to specify basic logging requirements, however, special logs should not be specified. Any other information from the area should be drawn on. Provides more flexibility to select the appropriate log to demonstrate adequate cement bond.

Response: EPA agrees with the suggested change. In the final GS rule, §146.87(a)(2)(ii) reads as follows: "A cement bond and variable density log to evaluate cement quality radially, and a temperature log after the casing is set and cemented."

EPA believes that a minimum suite of logs and tests is necessary at all GS wells. All logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved and has mechanical integrity. EPA adds that, should alternative methods be shown to provide equivalent or better information or if site-specific conditions and risk factors dictate that other logs are necessary, the Director has the discretion at §146.87(a)(5) to require further logs and tests if necessary and to approve alternative methods that provide equivalent or better information.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29184 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: 146.87(a)(4)

(4) A series of tests designed to demonstrate the internal and external mechanical integrity of injection wells, which may include:

(i) A pressure test with liquid or gas; (ii) A tracer survey such as oxygen-activation logging; (iii) A temperature or noise log; (iv) A casing inspection log, if required by the Director; and

(5) Any alternative methods that provide equivalent or better information and that are required of and/or approved of by the Director.

GWPC Recommendations: (4) Test(s) designed to demonstrate the internal and external mechanical integrity of injection wells, which may include:

(i) A pressure test with liquid or gas; (ii) Diagnostic tools such as oxygen-activation logging; (iii) A temperature or noise log; and (iv) A casing inspection log.

(5) Accept the EPA language and numbering.

Rationale: Technical and grammatical corrections

In (iv), "if required by the Director" is unnecessary.

We interpret that (5) applies to 146.87(a)Response: EPA agrees with the commenter about the wording of the casing inspection log requirement at §146.87(a)(4) and made the suggested change to improve clarity. In the final regulation, §146.87(a)(4)(iv) does not include the phrase, “if required by the Director.”

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29185 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule provision: 146.87(b)

EPA Proposal: (b) The owner or operator must take and submit to the Director whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core other

formations in the borehole.

GWPC Recommendations: (b) The owner or operator must submit to the Director a report describing whole cores or sidewall cores representative of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept data from cores and fluid samples from nearby wells if the owner or operator can demonstrate that such data are representative
of conditions in the wellbore.

Rationale: The information required should be sufficient to properly describe the injection and confining zones.

Response: EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

EPA believes that logs and tests must be performed on each well drilled regardless of existing information about the area to account for the complexity of CO2 injection well construction and thebuoyancy of CO2. Existing lithologic and geologic information may lack the details needed for sitespecific well design and the geology needed to support protection of USDWs from endangerment.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29186 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (c) The owner or operator must record the fluid temperature, pH, conductivity, reservoir pressure and the static fluid level of the injection zone(s).GWPC Recommendations: (c) Prior to injection well operation, the owner or operator must record the formation temperature, formation fluid pH and conductivity, and reservoir pressure of the injection zone(s).

Rationale: Technical corrections. Reservoir pressure and static fluid level are redundant parameters.

Response: EPA disagrees that "reservoir pressure" and "static fluid level" are redundant parameters. Although the static fluid level is equal to the bottom hole pressure, this may not always be identical to the reservoir pressure. Additionally, measuring the static fluid level provides additional assurance that the reading is accurate (or, provides the needed information in cases where a good reading is not obtained). In addition, a static fluid level measurement provides information regarding the proximity to USDWs that need protection afforded to them.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29187 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (d) At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zone(s):

(1) Fracture pressure; (2) Other physical and chemical characteristics of the injection and confining zones; and (3) Physical and chemical characteristics of the formation fluids in the injection zone.

GWPC Recommendations: Delete all

Rationale: With the exception of calculating fracture pressure, the requirements of this section appear redundant to other requirements of prior sections. Recommend moving injection pressure to old (e), now renumbered as (d).

(2) and (3) are also too vague.

Response: EPA believes that the requirement to provide information on the injection and confining zones in §146.87(d) is warranted, and that the rule provides flexibility to account for the variety of geologic conditions that may be encountered at GS sites.

EPA is developing guidance on monitoring and testing that will describe recommended tests andprocedures to assist owners/operators and Directors in evaluating the requirements for preoperational logging and testing under §146.87. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29188Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: EPA Proposal: (e) Upon completion, but prior to operation, the owner or operator must conduct the following tests to verify hydrogeologic characteristics of the injection zone:

(1) A pump test; or (2) Injectivity tests.

GWPC Recommendations: (d) At any time prior to injection well operation, the owner or operator must determine fracture pressures of the injection and confining zones and conduct tests to verify hydrogeologic and geomechanical characteristics of the injection zone, e.g., injectivity tests.

Rationale: Allows the use of information such as leak off tests conducted during the drilling operation.

Delete (1)

It was felt that Geomechanical properties were at least as important as hydrogeologic characteristics.

The results of a pump test (pumping fluid from the well) has no relevance for an injection well.

If current (d) is deleted as recommended, this would become (d)

Response: EPA clarifies that the owner or operator has the option of using pump tests or injectivity tests depending on which would provide the most valuable information based on site-specific conditions. Further, EPA disagrees that pump tests are irrelevant to determining injection zone properties. Depending on the characteristics or depth of knowledge of the confining and injection zone formations, pump tests may be necessary to prove that no hydraulic connection exists between the injection zone and a USDW.

EPA is developing guidance on monitoring and testing that will describe recommended tests andprocedures to assist owners/operators and Directors in evaluating the requirements for preoperational logging and testing under §146.87. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 29189 Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule language
Comment: Rule Provision: 146.87(f)

EPA Proposal: (f) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director 30 days prior to conducting the first test and submit any changes to the schedule 30 daysprior to the next scheduled test.

GWPC Recommendations: (e) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director upon spudding the well and submit any changes to the schedule 48 hours prior to the scheduled

test.

Rationale: The changes reflect the realities of flexible rig schedules and are fully consistent with current Class II requirements and practices.

If current (d) is deleted as recommended, this would become (e)

Response: EPA disagrees that the 30-day notification requirement is unreasonable. The 30-day notification mirrors the current requirement for logging and testing of new Class I wells, as described in §146.66. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide much needed field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ability to be involved.

Commenter Name: Donn Miller Letter ID: 0270 Commenter Organization: State of Oregon, Water Resources Department Comment ID: 22887
Comment: 146.87 Logging, Sampling, and Testing prior to Injection well Operation.

(b) This rule states that the Director may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The problem is that cores from nearby wells may not be indicative of the conditions at the well being constructed. If possible a down-hole video should be made to accurately show the
conditions at the well site.

Response: EPA clarifies that §146.87(b) allows information on cores from nearby wells to be submitted only if the operator can demonstrate that core retrieval is not possible and that cores from nearby wells are representative of conditions at the Class VI well. If the Director approves the use of alternate cores and determines that additional logs, such as video logs, are necessary to evaluate the site, he/she has authority under §146.87(a)(5) to require additional information.