This comment letter response contains two parts:

(1) The original submittal from the commenter. (2) A data base printout of EPA’s response to each point raised by the commenter.

Notes about the response letters:

• The response letters were generated by a data base used to track the content of all public

comment submittals and ensure that the Agency responds to each. Each comment letter

was assigned a Letter ID that corresponds to the last four digits of the docket number of the original comment (as posted on www.regulations.gov).

• Each response letter includes: comment text; an EPA

‐ assigned comment code; and an

individual response. These are described and explained below.

• The data base contains Comment text from the letters submitted by commenters.

Many hard copy letters were scanned into electronic format for inclusion in the data

base. As a result, there may be some typographical errors attributable to optical

character recognition issues. However, all original submittals were reviewed in the

process of drafting responses to ensure that the comment content was understood and appropriately addressed.

• The content of each comment letter was divided into topic areas and assigned a unique

Comment ID. Additionally, one or more Comment Codes (i.e., unique topic area ID) was assigned to each discrete point raised by a commenter. This information was added to

the data base. To inform final rulemaking decisions, all comments and information

received on a given topic were reviewed by technical experts in each rule area (e.g., on

construction requirements).

• Following decisions on the final rule requirements, Individual responses were drafted by topic area to ensure completeness and consistency of the responses with the final

rule and other responses to similar comments. Each discrete point made by a

commenter was given a unique response.

• Upon completion of comment responses, all information was entered into the data base.

Each letter response is a compilation of each comment and its individual response, compiled in the order of the original comment letter. As a result of this process, there is

repetition in the response text. The Agency believes this approach ensures completeness

and attention to each comment letter that was submitted.

• All comments in a topic area were reviewed, evaluated, and responded to concurrently.

Responses on each topic area are compiled and are also available in the rulemaking docket.December 23, 2008

Via Electronic Mail and Overnight Mail

Docket ID No.: EPA-HQ-OW-2998-0390

Cynthia C. Dougherty

Director Office of Ground Water and Drinking Water Environmental Protection Agency , Mailcode: 2822T 1200 Pennsylvania Ave., NW. Washington, DC 20460

Re: Hydrogen Energy International LLC’s Comments on United States Environmental Protection Agency’s Proposed Rule: Federal Requirements under the Undergr ound Injection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS) Wells

Dear Director Dougherty:

Hydrogen Energy International LLC (“HEI”) is pleased to submit its

comments on the United States En vironmental Protection Agency’s

(“EPA”) Proposed Rule: Federal Requirements Under the Underground Injection Control (UIC) Pr ogram for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS) Wells (“Proposed Rule”)

, published on July 25, 2008 for review and comment by the public (73 Fed. Reg. 43492-541). HEI appreciates the opportunity to participate in this rulemaking process and has been actively engaged in the process to date.

As an initial matter, we applaud EPA’s significant efforts to include and encourage broad stakeholder pa rticipation both before and after publication of the Proposed Rule. Fu rthermore, it is evident from the Proposed Rule that EPA considered and incorporated many of the stakeholders’ comments from the public workshops. Accordingly, EPA adopted a framework that is int ended to encourage the deployment of carbon capture and sequestration or stor age (“CCS”) in a manner that is protective of underground sources of drinking water (“USDWs”). There isHEI’s Comments To EPA’s Proposed Rule

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growing consensus among scientists, environmental groups and members of government that CCS will play a cr itical role in addressing greenhouse gas emissions.

The comments herein are founded on knowledge and experience gained through decades of industry oper ations, and are intended to provide constructive input on the Proposed Rule. HEI’s comments are based upon two important and mutually-achievable goals: (1) protecting USDWs; and (2) adopting regulations that are reas onable, cost-effective and facilitate geologic sequestration of CO 2 . HEI concurs with EPA’s conclusion that CCS presents a “key climate change mi tigation technology.” (73 Fed. Reg.

at 43495.)

In the context of geologic sequestration of CO 2 , it is imperative to maintain flexibility in the regulator y requirements due to the site-specific nature of this activity and because the technology is continually advancing. For geologic sequestration of CO 2 , “one-size-fits-all” is not an approach that is necessarily or reasonably protec tive of USDWs. Rather, each site has site-specific characteristics that merit differing requirements. Indeed, what may appear to be a standard prot ective measure in the context of a particular site could actually have the opposite effect and increase potential

risks at another site. (See A Technical Basis for Carbon Dioxide Storage

, CO 2 Capture Project, December 2008.)

Consequently, HEI strongly encourages EPA to provide performance standards for the various phases of a geologic sequestration project (i.e., site characterization, operation and site closure), while providing theDirector flexibility to add requirements as necessary to address sitespecific characteristics. This type of approach, consistent with Regulatory Alternative 2, offers the degree of fl exibility that the permitting authority will require to tailor fit-for-purpose requi rements that address site specific

characteristics. Furthermore, it ensures that project costs will be commensurate with the geologic risk, and will further the continued evolution of the best technologies.

Our comments address the following important topics: (A) Enhanced Oil Recovery or Enhanced G as Recovery (“EOR/EGR”) and CO 2 Storage; (B) Wells, Monitoring & Operat ions; (C) Site Closure Period; andHEI’s Comments To EPA’s Proposed Rule

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(D) Financial Assurance. HEI further joins in the comments submitted by

the American Petroleum Institute.

(A) Importance of EPA’s Re cognition That EOR/EGR and Storage of CO 2 Occur At the Same Time

HEI commends EPA for its recogniti on, as stated in the Preamble of the Proposed Rule, that oil and gas reservoirs will play a valuable role in the geologic storage of CO 2 . Two of the reasons cited by EPA are: (1) oil and gas reservoirs are natural storage c ontainers that have trapped fluid (both liquid and gaseous) hydrocarbons for millio ns of years; and (2) oil and gas exploration and production activities h ave created a wealth of knowledge and geologic data that can support t he site characterization process for geologic sequestration. (73 Fed. Reg. at 43502-03 .) Indeed, oil and gas reservoirs have proven capable of containing water-buoyant fluids for millions of years. These reservoirs are well studied and they offer the best opportunity to kick-start large-scale geologic sequestration of CO 2 , building on 100 years of oil and gas field oper ating experience. Consequently, many oil and gas reservoirs are available now to serve CCS projects at a commercial scale, and will add insights for subsequent application to other

formations.

EPA should provide further discu ssion and acknowledgement in its Proposed Rule that, when CO 2 is injected for use in EOR/EGR projects, geologic sequestration (or l ong term storage) of CO 2 occurs during EOR/EGR operations and continues after EOR/EGR operations cease

(“EOR and Storage”). Furthermore, it is critical that EPA support and encourage geologic sequestration of CO 2 in these well-studied and proven oil and gas reservoirs by amending ce rtain elements of the Proposed Rule to clarify and streamline requirement s. EPA’s recognition of EOR and Storage will provide a much-needed near-term, economic incentive to CCS projects. Incentivizing the use of anthropogenic CO 2 for EOR/EGR will provide many lasting benefits to the Un ited States, by significantly reducing

current CO 2 emissions and increasing energy security.

It has become increasingly clear that early EOR and Storage projects will significantly advance the deployment of CCS technology and geologic sequestration of CO 2 for many reasons:HEI’s Comments To EPA’s Proposed Rule

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• Oil and gas formations offer the best characterized sites among potential sinks for anthropogenic CO 2 ;

• Much of the required infrastruct ure and operational experience is already in place;

• Class II requirements have proven to be an effective regulatory framework in protecting USDWs in the context of CO 2 EOR operations, evidenced by more than 30 years of experience in the

Permian Basin and more than 25 years of miscible gas injection projects on the North Slope of Alaska (where CO 2 comprises 25% of the miscible gas injected);

• Demand for large volumes of CO 2 for EOR is increasing 1 ; and

• EOR can provide a revenue stream to supplement the economics of early-mover CCS projects.

EOR and Storage have the added benefit of increasing domestic energy supplies in the face of incre asing demand. Carbon dioxide injection has proven capable of increasing oil or gas recovery in mature fields from 5% to more than 20%. The Departm ent of Energy estimates that EOR has the potential to add 40-80 billion barrels of oil reserves in the United States, which is 2 to 4 times the current United States’s total proven reserve. The Intergovernmental Panel on Climate Change (“IPCC”) has agreed that EOR technology can provi de a significant kick-start on proving geologic sequestration of CO 2 on a commercial scale. Indeed, the early commercial scale CCS projects will probably employ EOR and Storage as their basis of design, which will extensively inform the technical development and safe deployment of CCS projects in other types of geologic formations. 2

1 Currently, over 2 billion cubic feet of natura lly-occurring CO 2 is used daily for EOR operations and the volume is growing.

2 Notably, it is estimated that site characterization of saline reservoirs will likely cost tens of millions of dollars and take years of study to permit one commercial scale saline storage

reservoir.HEI’s Comments To EPA’s Proposed Rule

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(1) Brief Explanation of EO R/EGR Operations Utilizing CO 2

Currently, EOR/EGR oper ators purchase CO 2 for injection. This can represent a significant portion of t he cost of an EOR/EGR project. Consequently, CO 2 is a valuable commodity to EOR/EGR operators and is treated accordingly. Because it is a valuable commodity in EOR/EGR operations, CO 2 is not emitted or vented to the atmosphere during operations or after operations cease. Any injected CO 2 that returns to the surface during production operations is separated from the hydrocarbons and re-injected for additional enhanced recovery use.

Approximately 30% to 50% of the injected CO 2 volume typically remains permanently stored in the oil or gas reservoir after production operations cease. The injected CO 2 is monitored in the formation and injection operations are designed to minimize CO 2 procurement and maximize oil (and recycled CO 2 ) production. Despite be st efforts to re-use

all the CO 2 , additional trapping of CO 2 occurs with each subsequent injection cycle, necessitating further purchases of CO 2 . When the EOR operations cease (and the field is blown down to recover any CO 2 available for use in another operation), wells are closed and the remainder of the injected CO 2 remains permanently stored under ground. However, an EOR operator could quite easily, at its opt ion, manage operations to store the injected CO 2 for the long term (rather than recover it).

The foregoing demonstrates that, b ased on decades of experience gained in existing EOR/EGR operations utilizing CO 2 , EPA should acknowledge in the Final Rule preamble that injected CO 2 can be trapped and stored for long term during EOR operations and continues afterwards. Furthermore, existing Class II regulations and industry practice employ proven methodologies to conduct these oper ations in a safe manner that is protective of USDWs.

(2) Requested Amendments to Proposed Rule

For the reasons stated above, EPA should expand its discussion and acknowledge in the Final Rule te xt and preamble that, when CO 2 is injected for use in EOR/EGR projects, geologic sequestration (or long term storage) of CO 2 occurs during EOR/EGR operations and continues after operations cease – thus EOR and Storage. HEI supports EPA’s statementHEI’s Comments To EPA’s Proposed Rule

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that EOR/EGR, as long as any produc tion is occurring, will continue to be permitted under the Class II program.

We also understand that it is EPA’s intent, which we strongly support, that the proven Class II progr am applies to storage of CO 2 that is occurring during and in connection with EOR/EGR operations. Such an approach is logical, technically sound, and protective of USDWs as demonstrated by decades of safe operations. Accordingly, EPA should amend the Proposed Rule language and expand its discussion in the Final Rule preamble to clarify that (a) when CO 2 is injected for EOR and Storage, the applicable requirements ar e under Class II; and (b) when CO 2 is exclusively injected for storage, th e applicable requirements are under

Class VI.

(i) Clear Well Classification With Respect to EOR and Storage

HEI requests that EPA amend sect ions 144.3, 144.6, 144.80, 146.5 and 146.81 of the Proposed Rule to cl arify that (a) Class II applies to EOR/EGR operations where geologic sequestration of CO 2 is occurring during or in connection with EOR/EGR operations or activities (i.e. EOR and Storage); and (b) Class VI applies w hen the exclusive purpose is geologic sequestration of CO 2 . In addition to the reasons stated above, this clarity is

needed because some amount of CO 2 is sequestered or stored during EOR/EGR operations regardless of the in tent of the operator . As currently drafted, the Proposed Rule may be interp reted – contrary to EPA’s intent – to require EOR/EGR operations to proceed under Class VI. API has submitted specific language to clarify that the applicable well class is Class II. We support API’s proposed language modifications to sections 144.3, 144.6, 144.80, 146.5 and 146.81 of the Proposed Rule.

In addition, we have participated in discussions among multistakeholders including environmental groups, various associations and

different industries (the “Multi-St akeholder Discussions Group”); we also support the language recommended in the correspondence from the MSDG dated December 23, 2008 (the “MSDG Proposal”) to sections 144.6, 144.80 and 146.5(f) establishing a “bright line” for wells injecting

CO 2 for EOR and Storage. The MSDG Proposal defines a “bright line” for wells that inject CO 2 for EOR and Storage, and consistent with EPA’sHEI’s Comments To EPA’s Proposed Rule

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intent, remain in Class II and are s ubject to the existing Class II regulations – which have adequately safeguarded US DWs in the context of EOR/EGR operations for decades.

The MSDG has also agreed to continue discussions regarding specific rules that would be appli cable to geologic sequestration of CO 2 in oil and gas formations following the completion of EOR/EGR production. We intend to participate in thes e negotiations. The development of a subclass under Class II or Class II-B regul ations would result in a regulatory framework that would effectively pr otect USDWs and also promote the geologic sequestration of CO 2 in oil and gas formations, especially following the cessation of EOR/EGR production activities.

The advantages of a subclass dedicated to geologic sequestration in oil and gas formations are that a Class II-B will address risks associated specifically with oil and gas formations, rely upon information and data gathered during the terminated EO R/EGR production activities and maintain permitting authority under a single agency with historical knowledge and expertise about the form er operations and the receiving oil and gas formation. This would maximize the efficient use of administrative resources and allow for seamless transitioning of operations from EOR and geologic sequestration of CO2 to injection of CO2 only for geologic sequestration.

HEI requests that EPA consider the foregoing discussion of a subclass or Class II-B wells for oil and gas formations for future rulemaking. However, in the context of the curr ent Proposed Rule, we submit the following recommendations on the question of grandfathering.

(ii) Grandfathering – Transitioning from EOR and Storage to Exclusively CO 2 Storage

After the EOR and Storage projects conclude production of oil or gas, injection of CO 2 may continue at the option of the operator to utilize fully all available pore space. EPA regulations should facilitate this

transition from EOR and Storage to exclusivel y storage operations when EOR/EGR operations are complet ed. EPA’s decision to allow grandfathering of construction requ irements in sections 146.81 and 146.86 of the Proposed Rule is an excell ent example of both protective andHEI’s Comments To EPA’s Proposed Rule

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reasonable regulation. HEI supports EPA’s proposal and recommends that EPA expand the grandfathering prov isions to encourage and facilitate continued injection of CO 2 exclusively for storage when EOR/EGR operations cease.

Specifically, the Proposed Rule should be modified also to allow grandfathering of sections 146.88(e) and (f) (continuous recording devices and down-hole automatic shut-off devices, respectively) regarding Operations; and Section 146.89(b) a nd (c) (continuous monitoring and specific yearly tests, respectively) rega rding Mechanical Integrity. Existing, operationally-compliant, Class II EOR -wells will continue to protect USDWs, as established by their operat ional histories, even when injection is for the exclusive purpose of CO 2 sequestration without the foregoing additional Operation or Mechanical Int egrity requirements. In addition, the following sections of the Proposed Rule simply will not be applicable or pertinent at the time of transition be cause these provisions presume that no injection has commenced. These sections are as follows:

• Permit Application § 146.82(g) and (j);

• Area of Review § 146.84 (b)(2)(iv), (c )(1) and (d);

• Logging Sampling and Testing § 146.87(a), (b) and (f); and

• Testing and Monitoring § 146. 90 (b), (d), (g) and (h).

These provisions should not and cannot apply when a Class II EOR and Storage project transitions to an e xclusively storage project because, as a practical matter, perform ance of certain “baseline measurements,” “model predictions,” “witnessing of logging a nd testing,” and “corrective actions” will not be possible prior to injection of CO 2

.

In sum, EPA should expand the grandfathering provisions to encourage continued storage of CO 2 after EOR/EGR operations have ceased. Most of the existing Class II requirements that were appropriate for regulation of EOR and Storage will continue to operate effectively and to safeguard USDWs during exclusively storage operations. Finally, appropriately expanded grandfathering will facilitate optim al utilization of these proven oil and gas reservoirs for geologic sequestration of CO 2

.HEI’s Comments To EPA’s Proposed Rule

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CCS in connection with EOR prov ides a forward-looking energy policy for the United States, as it will significantly reduce CO 2 emissions with the added benefit of increasing energy security through increased domestic oil production.

(B) WELLS, MONITORING & OPERATIONS

In general, regulations for geologi c sequestration should provide for effective storage management by requiring the following activities:

• Site characterization that valid ates the geological model of the storage site and confirms pot ential leakage pathways have been identified and evaluated;

• Risk assessment that builds up on the predicted behavior and

movement of the CO 2 in the reservoir over time and confirms that the potential for leakage has been evaluated through site

characterization; and

• A monitoring plan that measures the performance of the highest leakage risk parameters and validates or updates predictive performance models.

The appropriate implementation of thes e key areas will ensure the safe and secure operation of a geolog ic sequestration project.HEI’s Comments To EPA’s Proposed Rule

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(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

CO 2 . 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

CO 2 EOR/EGR wells in a safe and se cure manner. Notably, Class IIrequirements have proven to be effective in ensuring the nonendangerment of USDWs. Therefore, HE I believes it would be prudent to rely upon this extensive existing regulatory and industry experience and knowledge in setting Class VI require ments for wells that inject CO 2 for long term sequestration.

(2) Flexibility in Design of Moni toring Programs and Selection of Technologies

HEI agrees with EPA that monito ring is important. For example, once a site has been selected, appropriate baseline surveys should be conducted and analyzed prior to commencing operations. During operations and at site closure, appr opriate monitoring technologies should be applied to confirm the integrity and effectiveness of the storage site. However, there is a common misperception that, in order to achieve secure storage, a large amount of monitoring is required. The United Nations states that “the proportion of CO 2 retained by appropriately selected and managed sites is likely to exceed 99% over 1,000 years.” Thus, the key to secure storage is the appropriate selection and

management of the site and these activit ies should be the focus of any regulatory framework for CO2 geo-sequestration. If done properly, a

selected site will be secure with a m onitoring program that is designed and focused on the particular storage site.

HEI and its affiliated companies in BP have significant and highly relevant experience around monitoring of the subsurface and the surface. For many decades, BP has been effectively employing a number of monitoring technologies to ensure the saf ety and integrity of its customary oil and gas operations, including CO 2 EOR-related operations since the 1970’s in West Texas and Alaska. Notably, since 2004 BP has beenHEI’s Comments To EPA’s Proposed Rule

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operating the In Salah, Algeria, CO 2 storage project where BP (and partners) has been stori ng around 1 million tones CO 2 per year in a deep saline formation close to a producing gas field. The In Salah CO 2 Storage project also incorporates a research project to test CO 2 storage monitoring technologies with a program that is much more extensive than would be appropriate for a commercial project. At In Salah, BP is testing new technologies (such as satellite imagery and micro-seismic) and conventional oilfield technologies (s uch as tracers and conventional 3D seismic) to compare and contrast re sults as the partnership endeavors to design and develop monitoring technol ogies and methodologies that are reliable and cost-effective, given the expectation of future commercial application.

Before initiating injection at In Salah, BP conducted a thorough assessment of potential leakage paths at the site; BP then tailored the monitoring program to address those site-specific risks. There are two other monitored, industrial-scale CO 2 injection projects in the world (at Sleipner and Weyburn) and the si te-specific nature of monitoring requirements is demonstrated by comparing these three CO 2 storage projects – monitoring that works well at one location may not work at all in

another location.

With respect to monitoring r equirements in general, EPA should adopt regulations that are performance and risk-based and will result in a site-specific monitoring program that is designed to understand the location, movement and stabilization of the CO 2 plume in the subsurface as well as the early identification of an y leakage for appropriate corrective action. HEI commends EPA for its efforts in this regard, but believes that further modification is necessary. HEI agrees with the proposal to allow a phased approach to conduct corrective acti on in an Area of Review that has pre-existing well penetrations. Existing wells within the AoR may be ideal candidates for conversion to monitoring or injection wells during the life of the project and, therefore, shoul d not be plugged and abandoned prior to injection. Existing wells within the likely plume area th at are not plugged and abandoned should have diagnostic testing to ensure there is minimal risk of vertical leakage prior to conver sion to monitoring or injection status.

Furthermore, in various parts of the Proposed Rule, EPA has prescribed particular monitoring tec hnologies. Mandating any specificHEI’s Comments To EPA’s Proposed Rule

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technology(ies) would have the adverse effect of (1) promoting particular technologies to the exclusion of other developed – and to be developed – technology(ies), and (2) substantially increasing costs without necessarily contributing to the protection of USDWs. This would hinder the development and deployment of CCS at commercial scale. Moreover, it would discourage the development of ot her technologies. HEI therefore strongly discourages EPA from promulga ting regulations that mandate the use of any specific monitoring technology.

(3) Specific Comments

In 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 “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 CO 2 Geological Storage Project: Wells , by Christopher, Crow, Dodds, Wright, Williams, March 2008.

HEI strongly discourages EPA from setting a requirement to use degradation-resistant materials & cemen t. Actual field observations based upon sampling of in situ casing and annular cements do not support this general requirement. The studies refe renced by EPA in its Preamble exposed cement in a laboratory setti ng to a continuously-refreshed supply

of CO 2 -saturated brine, which then r eportedly caused the cement to degrade. (Duguid et al., 2004 and Kut chko et al., 2007.) These studies represent variations in cement alte ration rates due to curing and exposure conditions, but neither supports th e requirement for the use of degradation-resistant materials a nd cement because the laboratory procedures that were used do not nece ssarily represent the actual barrier exposure conditions in an appropriate ly cemented operating well. Indeed, the findings of Kutchko’s laborat ory study suggested there would beHEI’s Comments To EPA’s Proposed Rule

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limited degradation even after decades, wh ich is consistent with the field study results of Carey et al., 2007.

EPA’s rulemaking should give cons iderable 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 CO 2 Capture Project, 2008).

Both of these field studies identif ied that hydraulic isolation was maintained across the caprock, and the majority of cement reaction was

localized to the area near the CO 2 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 prim ary means of achieving this objective.

Based on the foregoing, degradation -resistant materials should not be mandated for all projects, without rega rd to site-specific characteristics. Rather, the application of degradation-re sistant materials & cement, if any, should be defined on site-specific characteristics.

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 mainta in 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 re move any ambiguity regarding the performance-based approach set forth in the Proposed Rule.

Furthermore, section 146.86(b)(5) should be amended to base the choice of casing and cement material s on the planned operat ing life of the well as opposed to the ultimate duration of the geologic sequestration project. EPA may have set the durati on as the life of the project in an effort to prevent corrosion of the casi ng over the long term after injection has ceased. However, this legitimate concern is mitigated by appropriate plugging of the static we ll at the end of its life. This plugging could employHEI’s Comments To EPA’s Proposed Rule

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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).

(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 amou nt of research in this area and is well informed on this topic. HEI has direct experience with horizontal wells used in connection with geologic seque stration. At In Salah, 1mmtpa CO2 is being sequestered in a formati on 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 Un ited States. To do this, requires only three wells, but the wells have very l ong 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. Additi onally, horizontal wells can reduce the risk of leakage because their use limit s the number of penetrations through the caprock. There are other options to optimize injectivity as well that include, but should not be limited to, hy draulic fracture trea tments, multiple injection points along the wellbore and open hole completions.

(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 characteri stics. Cement should cover the uppermost caprock (within the Area of Review) by approximately 500 feet;HEI’s Comments To EPA’s Proposed Rule

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cement coverage should not be required all the way to surface. The ultimate decision for each project shoul d rest with the Director since each storage site is unique in the geological intervals of the cap rock(s), injection zone(s) and position relative to US DW(s). Moreover, any expectation to cement in the injection interval s hould permit the use of external casing packers or other isolation method s in conjunction with cementing requirements across the caprock, as discussed above.

(iv) Definition of Carbon Dioxide Stream

Section 146.81 of the Proposed Ru le defines “carbon dioxide

stream” as follows:

Carbon dioxide stream means carbon dioxide that has been captured from an emission source (e.g., a power plant), plus incidental

associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injectio n process. This subpart does not apply to any

carbon dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261.

By limiting the definition to “emissi on sources,” the Class VI regulations may have the unintended effect of na rrowing the types of sources that might inject CO 2 for geologic sequestration. The particular source of the

CO 2 is not material in terms of prot ecting USDWs. Furthermore, the Final

Rule should not address the source because it is beyond the scope of this regulation. We recommend deleting the phrase “has been captured from an emission source (e.g., a power pl ant)” from the definition contained in

section 146.81 of the Pr oposed Rule so that the Final Rule does not inadvertently preclude other non-emission sources of CO 2

.

(v) EPA Should Not Restrict Injection To Below LowerMost USDW

The Proposed Rule restricts injection of CO 2 to below the lowermost USDW. (See §§ 144.6(f), 146.5(f) and 146.81.) EPA acknowledges that such a restriction would preclude the consideration and use of various potential storage sites, and has requested comment on this approach.HEI’s Comments To EPA’s Proposed Rule

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HEI disagrees with such a blanket restriction, one that would pose a barrier to many, viable storage site s. The imposition of an artificial constraint limiting injection only to reservoirs below the USDW is not justified by technical knowledge or hi storical industry experience. For example, Class II requirements have proven successful in protecting USDWs even though injection into certa in reservoirs has occurred above

the lower-most USDW. Given the EPA’s effort in adopting a general performance-based approach, injecti on should be allowed to proceed into acceptable reservoirs provided the re servoir is demonstrated to provide

secure CO 2 storage above and below t he injection formation.

A containment system with appropri ate site characterization, risk assessment and monitoring is the key to secure storage and protection of USDWs. Proximity of t he injection zone to USDWs (i.e. whether shallower or deeper) is not the appropriate criter ia for protection of USDWs because proximity alone does not materially impact risk of leakage. Similarly, EPA should not establish minimum depths for CO 2 injection. Instead, any constraints placed on injection should be site-specific, consistent with the containment and capacity parameters of the storage site in question.

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 ce rtain potential storage sites USDWs may be located at depth; consequently, it w ould be technologically infeasible to construct surface casing to the requisi te depth prescribed by the Proposed

Rule.

In summary, EPA should not mandate a requirement of injection only below the lower-most USDW nor a minimum depth for injection of

CO 2 . Such a comprehensive prohibit ion would unjustifiably exclude potential storage sites that do not pose an endangerment to USDWs.

(vi) Injection Well Operation & Mechanical Integrity Requirements

Consistent with the earlier discu ssion about blanket construction limitations, HEI also disagrees with universal mandates regarding certain

CO 2 injection operations. EPA s hould not include automatic downholeHEI’s Comments To EPA’s Proposed Rule

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shut-in devices as a standard requirement for CO 2 injection wells (section 146.88(e)). An across-the-board requi rement for installation of downhole devices is excessive – unsupported by technical knowledge and industry experience – and would impose unnec essary costs. Overpressure protection is best achieved by ensuri ng compatibility of the casing/tubing material design strength with the surf ace injection (compression) system. Downhole shut-in devices may be appropriate, however, for site-specific situations (such as offshore), but they should not be mandated for all storage sites. Rather, the requirem ent of downhole shut-in devices should

be left to the discretion of the Director.

With regard to validating mechanical integrity of CO2 injection wells, HEI generally agrees with EPA’s suggestion to evaluate the “absence of significant leaks” by monitoring at some regular frequency the injection pressure, flow rate, injected volume s and the annular pressure. (See §

146.89 (b).) An alternative method for determining mechanical integrity, as noted by EPA, is periodic pressure testing; this should remain an option for site-specific cases. Where periodic pr essure testing is implemented, the pressure should be considered by e valuation of the formation potential instead of casing burst or tubing collapse limit.

The frequency of the monitoring should be defined not as “continuous” but as “regular ” or “periodic” based upon site characteristics because regular monitoring (e.g., every minute or hour) will often be adequate. For example, fluid volume in the annulus is static and requires evaluation of a pressure pulse to det ermine the depth of top of fluid. Therefore, this should be monitored on a monthly or quarterly basis to support the pressure data.

Section 146.89(c) lists specific methodologies to monitor fluid movement. HEI strongly disagrees with the requirement of any particular methodology because this would limit technology development and favor certain technologies to the exclusion of others without any rationale basis.

(C) SITE CLOSURE PERIOD

EPA correctly states in its Preamb le that defining the post-injection site care period is “difficult to define because it is based on site-specific considerations.” (73 Fed. Reg. at 43519.) The three studies cited by EPAHEI’s Comments To EPA’s Proposed Rule

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also concluded that “ the actual time for CO2 plume stabiliziation . . . will be very site-specific , being influenced by geologic factors such as formation permeability, geochemistry, and the degree of capillary trapping.” (Id .) However, the Proposed Rule establishes a default 50-year period (following the cessation of injection) duri ng which the operator must conduct monitoring to demonstrate that “the carbon dioxide plume and pressure front have stabilized and the geologic sequestration project does not pose an endangerment to USDWs.” (See § 146.93(b).) The designation of a 50- year time-period without regard to parti cular site characteri stics is arbitrary and not supported by existing scientific studies or industry experience. Moreover, the 50-year timeframe does not provide any incremental benefit as compared with a performance standard to protecting USDWs; rather, it will be a significant deterrent to co mmercial investment in geologic sequestration projects.

HEI urges EPA to adopt the performance standard that EPA

considered in its review. EPA consi dered three options: (1) fixed period; (2) performance standard; and (3) co mbination of fixed period and performance standard; EPA states it adopted the latter approach. (73 Fed. Reg. at 43519.) While the Proposed Rule allows a Director to reduce the 50-year minimum (§146.93(b)(2)), the pr actical effect will be the 50-year timeframe applies unless an operator is able to overcome the presumption built into the Proposed Rule that 50 years is adequate. Indeed, this is more prescriptive than the requirem ent for Class I hazardous wells, which provides that the timeframe for po st-injection site care ends when the plume has stabilized and cannot endanger USDWs. (Id. ; 40 CFR §146.71.)

EPA should adopt the performance-based standard that it considered previously. Accordingly, the post-injection site care period ends when monitoring and other site-specific data demonstrate that the geologic sequestration project does not pose an endangerment to USDWs. (See

e.g. , 73 Fed. Reg. 43520.) A performance-based approach is consistent with technical knowledge and historic industry experience. The site closure period would be appropriately based on particular site characteristics and historic site perfo rmance. For example, a well-selected and -managed sequestration site (such as an existing oil or gas field) that has met its performance objectives (including plume stabilization) will be much more secure and could be closed reasonably quickly (potentially, in as few as 2-3 years). At other site s that are less well confined (e.g., deepHEI’s Comments To EPA’s Proposed Rule

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saline formation without a conv entional 4-way closure), the CO 2 could move around for some time even after injection ceases before stabilizing, and might therefore require a longer period to allow for additional residual and solubility trapping.

In summary, HEI recommends that EPA adopt a performance-based approach to determine the timeframe for site closure. We also support the

site closure standard offered in th e MSDG Proposal for section 146.93(b),

which sets forth detailed criteria that must be satisfied to demonstrate that the site does not pose an endangerment to USDWs. The advantage of the MSDG Proposal as opposed to a fixed period is it establishes clear criteria that an operator must demonstrate before obtaining site closure based upon particular site characteristics and is, therefore, reasonable applicable to any storage site as opposed to a st andard based upon a fixed-duration. The current proposal of 50-years mini mum, even subject to potential reduction, would result in significantly discouraging the depl oyment of this technology at commercial scale without providing measurable additional protection of USDWs.

(D) EPA’s Proposed Financial Responsibility Demonstration Requirements

The proposed financial assurance requirements for Class VI UIC wells require the owner or operator to establish financial responsibility (or

“financial assurance”) to cover the costs of plugg ing and abandoning injection wells, as well as the costs of corrective action, post-injection site care, site closure and emergency and remedial responses. (73 Fed. Reg. at 43537; §146.85.) The financial responsibility requirements should be consistent with the need to protect USDWs, while being reasonable and cost-effective, yet facilitat ing geologic sequestration of CO 2. We support EPA’s proposed approach that allows for a wide range of financial

assurance mechanisms to be utilized to demonstrate financial responsibility. We also suggest that EPA adopt a flexible, iterative approach to financial assurance in keeping with the phased, adaptive management philosophy of other aspects of the Proposed Rule.HEI’s Comments To EPA’s Proposed Rule

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(1) Allow for a Broad Range of Financial Assurance Mechanisms

We support an approach that takes into account changing market

conditions and other factors and allo ws an operator to utilize a wide range and variety of financial assurance mechanisms to demonstrate financial responsibility. This should be coupled with the flexibility to combine multiple types of financial assurance mechanisms to demonstrate compliance. The regulations or guidance should be flexible and authorize EPA to accept and recognize other ty pes of instruments, programs or conditions that provide similar reliable assurance.

While the Proposed Rule does not limit the range of financial assurance mechanisms, EPA indicates that the Agency is considering revising various guidance documents re lated to financial assurance. (73 Fed. Reg. at 43520-21.) EPA refers to several reports issued by the United States General Accountability Office (“ GAO”), Office of Inspector General (“OIG”), and the Environmental Fina ncial Advisory Board (“EFAB”). Id. In 2003, the GAO issued a report reviewing, in part, the financial assurance requirements for Class I injection wells. See GAO Report to the Honorable Lynn C. Woolsey, House of Representatives, Deep Injection Wells: EPA

Needs to Involve Communities Earlier and Ensure that Financial Assurance Requirements are Adequate , GAO-03-761, 17-22 (June 2003). GAO noted that there is uncertainty about the adequacy of financial assurance requirements, but did not make any conclusions about specific mechanisms. Similarly, in 2005, OIG issued a report reviewing the financial

assurance mechanisms under the RCRA program. OIG Evaluation Report, Continued EPA Leadership Will Support State Needs for Information and

Guidance on RCRA Financial Assurance , Report No. 2005-P-00026 (Sept. 26, 2005). OIG concluded that despi te ongoing concerns, the lack of uniform national data prohibited read y identification of the problems. Id. at

8.

As EPA develops revisions or potential modifications to financial assurance guidance that would be applied to UIC permits, it should provide further public notice, review and enga gement opportunities that allow for feedback to EPA on specific proposals.HEI’s Comments To EPA’s Proposed Rule

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(2) EPA’s Suggestion for a Phased Approach to Financial Assurance for Post-Injection Site Care Should be Adopted

EPA is relying on an adaptive management approach for regulation

of CO 2 injection. (73 Fed. Reg. at 43522.) EPA specifically requested comment on allowing separate financial demonstration to be submitted for well-plugging and for post-injection site care. In the Preamble, EPA states

that:

Since post-injection site care has the potential to extend many years into the future, subsequent to the time a permit is issued, the Agency believes that it may be advan tageous to require the approval of the well plugging fi nancial demonstration at permit issuance and the post-injection site care financial demonstration at a later time (e.g., within 180 days of notifying the Director that the well will be plugged and abandoned). Trying to determine the cost for postinjection site care, possibly 30 to 50 years in the future, could be difficult, as could the approval of a financial demonstration.

(73 Fed. Reg. at 43522.) We agree with EPA’s stated rationale and recommend that EPA specifically inco rporate language in the Final Rule

that describes the manner in which determinations and demonstrations of financial assurance for post-injection site care will be postponed until a later time as discussed by EPA.

(3) Clarifying that adaptive management approach allows for phased financial assurance release

In accordance with the adaptive management approach for CCS, the rulemaking should clarify that the financial assurance can be released (or amounts reduced) as particular activit ies are completed and regulatory criteria are met (e.g., well plugging fo r corrective action). Also, the owner or operator should be able to use si te-specific data gathered from such activities to support revisions to site-specific financial assurance requirements.HEI’s Comments To EPA’s Proposed Rule

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CONCLUSION

HEI commends EPA for the tremendous amount of work that EPA has done in preparing the Preamble and Proposed Rule in an expedited

timeframe. After due consideration of studies and analyses performed by international research organizati ons, non-governmental organizations, sister-agencies, and scientists worldw ide, EPA’s research has determined that CCS could be “a key mitigati on technology for achieving domestic emissions reductions,” and CCS has the “potential to play a significant role in climate change mitigation scenari os.” (73 Fed. Reg. at 45496.) HEI applauds EPA’s willingness to play a significant role in this Nation’s strategy to address climate change. We are very supportive of EPA’s effort to implement a regulatory sc heme that will both protect one of our vital resources, USDWs, and fac ilitate the implementation of CCS technology and geologic sequestration of CO 2

.

Significantly, this technology does not start on a blank slate. The Oil & Gas industry has extensive, relevan t experience with injection into the subsurface that can inform this rulemaking. Moreover, BP is a leader in studies and demonstration projects conducted around the world regarding geologic sequestration of CO 2 . The comments submitted here are in large measure based upon this significant experience and technical knowledge. We would be pleased to review our comments and/or any questions that EPA may have regarding our comments at EPA’s convenience. HEI also welcomes the opportunity to provide addi tional information or input to EPA as EPA continues its evaluation and study of comments, scientific papers/studies or other information submitted or considered in this rulemaking process.

Please contact the undersigned with any questions or comments.

____________________________________ Tiffany Rau Policy & Communications Manager Hydrogen Energy International LLCLetter ID: 0224 Commenter: Tiffany Rau Organization: Hydrogen Energy International

Letter ID: 0224 Comment ID: 21646 Letter Lines: 44 to 53

Comment Code: 1330 1.1.3.1 Support use of GS in general

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

Comment: As an initial matter, we applaud EPA’ s significant effort s to include and encourage broad stakeholder participation both before and af ter publication of the Proposed Rule. Furthermore, it is evident from the Proposed Rule that EPA considered and incorporated many of the stakeholders’ comments from the public workshops. Accordingly, EPA adopted a fram ework that is intended to encourage the deployment of carbon capture and se questration or storage ("CCS") in a manner that is protective of underground s ources of drinking water ("USDWs"). There is growing consensus among scientists , environmental groups and members of government that CCS will play a criti cal role in addressing greenhouse gas

emissions.

Individual Response: EPA agrees that input of and part icipation by a wide spectrum of stakeholders is a vital compone nt of successful rulemaking. The Agency appreciates the degree of cooperation, participation, and active dialogue between the EPA and stakeholders and will

continue to work with stakeholders and experts as it implements the GS rule.

Letter ID: 0224 Comment ID: 21647 Letter Lines: 55 to 61

Comment Code: 1330 1.1.3.1 Support use of GS in general

Comment: The comments herein are founded on knowle dge and experience gained through decades of industry operations, and are in tended to provide constructive input on the Proposed Rule. HEI’s comments are based upon two important and mutuallyachievable goals: (1) protecting USDWs; and (2) adopting regulations that are reasonable, cost-effective and facilitate geologic sequestration of CO2. HEI concurs with EPA’s conclusion that CCS pres ents a "key climate change mitigation technology." (73 Fed. Reg. at 43495.)

Individual Response: EPA acknowledges the comment. Pleas e see the remainder of EPA’s responses to this comment for further deta ils. For additional information on EPA’s final regulatory approach, please see the final rule and preamble as well as the rulemaking docket.

Letter ID: 0224 Comment ID: 21648 Letter Lines: 63 to 83

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

1Comment: In the context of geologic sequestration of CO2, it is imperative to maintain flexibility in the regulatory requirement s due to the site-specific nature of this activity and because the technol ogy is continually advancing. For geologic sequestration of CO2, "one-size-fi ts-all" is not an approach that is necessarily or reasonably protective of USDWs. Rather , each site has sitespecific characteristics that merit diffe ring requirements. Indeed, what may appear to be a standard protective measur e in the context of a particular site could actually have the oppos ite effect and increase pot ential risks at another site. (See A Technical Basis for Carbon Di oxide Storage, CO2 Capture Project, December 2008.)

Consequently, HEI strongly encourages EP A to provide performance standards for the various phases of a geologic se questration project (i.e., site characterization, operation and site clos ure), while providi ng the Director flexibility to add requirements as n ecessary to address site-specific characteristics. This type of approach, consistent with Regulatory Alternative 2, offers the degree of flexibility that the permitting authority will require to tailor fit-for-purpose requirement s that address site specific characteristics. Furthermore, it ensures th at project costs will be commensurate with the geologic risk, and will further the continued evolution of the best technologies.

Individual Response: The Agency believes that the Class VI requirements balance site-specific flexibility with USDW protection. Rather than setting performance or technology-based standards for GS projects, EPA is adopting a flex ible approach, where operators of GS projects would develop and implement site-specific plans for delineating the AoR, testing and monitoring the site, performing corrective actio n, and post-injection site care . EPA believes that the plans— which would be reviewed and approved by the Director and periodical ly updated throughout the life of the project—promote an ongoing dialogue between the operato r and the Director that will encourage use of the most appropriate t echnologies for a particular project.

To address the comment that the rule should accommodate future technological developments related to GS, EPA adds that it is using an ad aptive approach to regulating GS under the UIC Program. Even after finalization of the GS regulat ion, EPA plans, every six years, to collect and review project data on GS research projects to determine whether the appropriate amount and types of information and appropriate documenta tion are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Letter ID: 0224 Comment ID: 21649 Letter Lines: 85 to 88

Comment Code: 1000 1. General and Administrative Comments

Comment: Our comments address the following important topics: (A) Enhan ced Oil Recovery or Enhanced Gas Recovery ("EOR/EGR") a nd CO2 Storage; (B) Wells, Monitoring & Operations; (C) Site Closur e Period; and (D) Financial Assurance. HEI further

2joins in the comments submitted by the American Petroleum Institute.

Individual Response: EPA acknowledges the comment. Pleas e see the remainder of EPA's responses to this comment and API’s comments for further details. For additional information on EPA's final regulatory approach, please see the final rule and preamble, including Class II/EOR wells, testing and monitoring, operating requirements , post-injection site car e, site closure, and financial assurance, as well as the rulemaking docket.

Letter ID: 0224 Comment ID: 21650 Letter Lines: 90 to 243 ; 778 to 782

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

Comment: (A) Importance of EPA’s Recognition That EOR/EGR and Storage of CO2 Occur At the Same Time

HEI commends EPA for its recognition, as st ated in the Preamble of the Proposed Rule, that oil and gas reservoirs will play a valuable role in the geologic storage of CO2. Two of the reasons cited by EPA are: (1 ) oil and gas reservoirs are natural storage containe rs that have trapped flui d (both liquid and gaseous) hydrocarbons for millions of years; a nd (2) oil and gas exploration and production activities have created a wealth of knowledge and geologic data that can support the site characterization pr ocess for geologic sequestration. (73 Fed. Reg. at 43502-03.) Indeed, oil and gas reservoirs have proven capable of containing water-buoyant fluids for millions of years. These reservoirs are well studied and they offer the best opportunity to kick-start large-scale geologic sequestration of CO2, building on 100 y ears of oil and gas field operating experience. Consequently, many oil and ga s reservoirs are available now to serve CCS projects at a commercial scale, and will add insights for subsequent application to other formations.

EPA should provide further discussion and ack nowledgement in its Proposed Rule that, when CO2 is injected for use in EOR/EGR projects, ge ologic sequestration (or long term storage) of CO2 occurs during EOR/EGR operati ons and continues after EOR/EGR operations cease ("EOR and Stor age"). Furthermore, it is critical that EPA support and encourage geologic sequestration of CO2 in these wellstudied and proven oil and ga s reservoirs by amending certain elements of the Proposed Rule to clarify and streamline requirements. EPA’s recognition of EOR and Storage will provide a much-needed near-term, economic incentive to CCS projects. Incentivizing the use of anth ropogenic CO2 for EOR/EGR will provide many lasting benefits to the United St ates, by significantly reducing current CO2 emissions and increasing energy security.

It has become increasingly clear that early EOR and Storag e projects will significantly advance the deploymen t of CCS technology and geologic sequestration of CO2 for many reasons:

3- Oil and gas formations offer the best characterized sites among potential sinks for anthropogenic CO2;

- Much of the required infr astructure and operational e xperience is already in place;

- Class II requirements have proven to be an effective regulatory framework in protecting USDWs in the context of CO2 EOR operations, evidenced by more than 30 years of experience in the Permian Basin a nd more than 25 years of miscible gas injection projects on the Nort h Slope of Alaska (where CO2 comprises 25% of the miscible gas injected);

- Demand for large volumes of CO2 fo r EOR is increasing [FN1]; and

- EOR can provide a revenue stream to supplement the economics of early-mover CCS projects.

EOR and Storage have the added benefit of increasing domestic energy supplies in the face of increasing demand. Carbon dioxi de injection has proven capable of increasing oil or gas recovery in mature fields from 5% to more than 20%. The Department of Energy estimates that EO R has the potential to add 40-80 billion

barrels of oil reserves in the United Stat es, which is 2 to 4 times the current United States’s total proven reserve. The Intergovernmental Panel on Climate Change ("IPCC") has agreed that EOR tec hnology can provide a significant kickstart on proving geologic sequestration of CO2 on a commercial scale. Indeed, the early commercial scale CCS projects will probably employ EOR and Storage as their basis of design, which will extensiv ely inform the technical development and safe deployment of CCS projects in ot her types of geologic formations.[FN2]

(1) Brief Explanation of EOR/ EGR Operations Utilizing CO2

Currently, EOR/EGR operators purchase CO2 for injection. This can represent a significant portion of the cost of an EO R/EGR project. Consequently, CO2 is a valuable commodity to EOR/EGR operators and is treated acco rdingly. Because it is a valuable commodity in EOR/EGR operations, CO2 is not emitted or vented to the atmosphere during operations or af ter operations cease. Any injected CO2

that returns to the surface during production operations is separated from the hydrocarbons and re-injected for addi tional enhanced recovery use.

Approximately 30% to 50% of the inj ected CO2 volume typically remains permanently stored in the oil or gas reservoir after production operations cease. The injected CO2 is monitored in the formation and injection operations are designed to minimize CO2 procurement and maximize oil (and recycled CO2) production. Despite best efforts to re-use all the CO2, additi onal trapping of CO2 occurs with each subsequent injecti on cycle, necessitating further purchases

4of CO2. When the EOR operations cease (a nd the field is blown down to recover any CO2 available for use in another operation), wells are closed and the remainder of the injected CO2 remains pe rmanently stored underground. However, an EOR operator could quite easily, at its option, manage operations to store the injected CO2 for the long term (rather than recover it).

The foregoing demonstrates that, based on decades of experience gained in existing EOR/EGR operations utilizing CO 2, EPA should acknowledge in the Final Rule preamble that injected CO2 can be trapped and stored for long term during EOR operations and continues afterwar ds. Furthermore, existing Class II regulations and industry pr actice employ proven methodol ogies to conduct these operations in a safe manner th at is protective of USDWs.

(2) Requested Amendments to Proposed Rule

For the reasons stated above, EPA should expand its discussion and acknowledge in the Final Rule text and preamble that , when CO2 is injected for use in EOR/EGR projects, geologic sequestration (o r long term storage) of CO2 occurs during EOR/EGR operations and continues af ter operations cease - thus EOR and Storage. HEI supports EPA’s statement that EOR/EGR, as long as any production is occurring, will continue to be permitted under the Class II program.

We also understand that it is EPA’s intent , which we strongly support, that the proven Class II program applies to storage of CO2 that is occurring during and in connection with EOR/EGR operations. Such an approach is logical, technically sound, and protective of USDWs as demonstr ated by decades of safe operations. Accordingly, EPA should amend the Pr oposed Rule language and expand its discussion in the Final Rule preamble to cl arify that (a) when CO2 is injected for EOR and Storage, the applicable re quirements are under Class II; and (b) when CO2 is exclusively injected for st orage, the applicable requirements are

under Class VI.

(i) Clear Well Classification With Respect to EOR and Storage

HEI requests that EPA amend sections 144.3, 144.6, 144.80, 146.5 and 146.81 of the Proposed Rule to clarify that (a) Class II applies to EOR/EGR operations where geologic sequestration of CO2 is o ccurring during or in connection with EOR/EGR operations or activities (i.e. EOR and Storage); and (b) Class VI applies when the exclusive purpose is geol ogic sequestration of CO2. In addition to the reasons stated above, this clarit y is needed because some amount of CO2 is sequestered or stored during EOR/EGR operations regardless of the intent of the operator. As currently drafted, the Proposed Rule may be interpreted - contrary to EPA’s intent - to require EOR/EGR operations to proceed under Class VI. API has submitted specific language to clarify that the applicable well class is Class II. We support API’s proposed language modifications to sections 44.3, 144.6, 144.80, 146.5 and 146.81 of the Proposed Rule.

5In addition, we have participated in discussions among multi-stakeholders including environmental groups, various a ssociations and diffe rent industries (the "Multi-Stakeholder Di scussions Group"); we al so support the language recommended in the correspondence from the MSDG dated December 23, 2008 (the "MSDG Proposal") to sections 144.6, 144.80 and 146.5(f) establishing a "bright line" for wells injecting CO2 for EOR and Storage. The MSDG Proposal defines a "bright line" for wells that inject CO2 fo r EOR and Storage, and consistent with EPA’s intent, remain in Class II and are subject to the existing Class II regulations - which have ade quately safeguarded USDWs in the context of EOR/EGR operations for decades.

The MSDG has also agreed to continue di scussions regarding sp ecific rules that would be applicable to geologic sequestra tion of CO2 in oil and gas formations following the completion of EOR/EGR produc tion. We intend to participate in these negotiations. The development of a subclass under Class II or Class II-B regulations would result in a regulatory framework that would effectively protect USDWs and also promote the geologi c sequestration of CO 2 in oil and gas formations, especially following the cessa tion of EOR/EGR production activities.

The advantages of a subclass dedicated to geologic sequestration in oil and gas

formations are that a Class II-B will addr ess risks associated specifically with oil and gas formations, rely upon information and data gathered during the terminated EOR/EGR production activities a nd maintain permitting authority under a single agency with historical knowledge and expertise about the former operations and the receiving oil and gas formation. This would maximize the

efficient use of administrative resources and allow for seamless transitioning of operations from EOR and geologic seque stration of CO2 to injection of CO2 only for geologic sequestration.

1 Currently, over 2 billion cubic feet of na turally-occurring CO2 is used daily for EOR operations and the volume is growing. 2 Notably, it is estimated that site char acterization of saline reservoirs will likely cost tens of millions of dollars and take years of study to permit one commercial scale saline storage reservoir.

Individual Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of ER, and that site s used for ER may be suitable for GS and may be among the first GS sites. However, the Agen cy believes that the na ture and risks of CO2 injection for the primary purpose of long term stor age poses different risks than injection for the primary purpose of EOR, and therefore has devel oped new Class VI regulations to address these unique risks. For example, the volume of CO2 anticip ated to be injected for long term storage is significantly greater than for EOR operations. Reservoir pressure conditions will also be different, with Class VI injection operations i nvolving large volumes of CO2 and likely having higher pressures within their stor age formations than Class II EO R projects, which may lead to fluid movement that endangers a USDW.

6The final Class VI regulations re quire that any owner or operato r injecting CO2 for the primary purpose of long term storage obtain a Class VI pe rmit with some special consideration for the fact that they are transitioning from a well not or iginally designed to meet Class VI requirements. The Director has the authority to determine at wh at point a Class VI permit is required for those projects that are transitioning from the primar y purpose of EOR to long term storage of CO2. The final regulation provides a set of technical factors for the Direct or to evaluate in making this determination, at §144.19. EPA believes that this approach provides su fficient protection of

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

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

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

EPA clarifies that the GS rule does not require a ny facilities to sequester CO2; nor does it create an economic incentive to do so. The purpose of the GS regulation is to ensure that, where deployed, GS is conducted in a manner that does not endanger USDWs.

Letter ID: 0224 Comment ID: 21651 Letter Lines: 245 to 300

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

Comment: HEI requests that EPA consider the fore going discussion of a subclass or Class II-B wells for oil and gas formations for future rulemaking. However, in the context of the current Proposed Rule, we submit the following recommendations on the question of grandfathering.

(ii) Grandfathering - Transitioning from EOR and Storage to Exclusively CO2 Storage

After the EOR and Storage projects conclude production of oil or gas, injection of CO2 may continue at the option of the operator to ut ilize fully all available pore space. EPA regulations should facili tate this transition from EOR and Storage to exclusively storage operations when EOR/EGR operations are completed. EPA’s decision to allow grandfathering of construction requirements in sections 146.81 and 146.86 of the Proposed Rule is an excellent example of both protective and reasonable regul ation. HEI supports EPA’s proposal and recommends that EPA expand the grandf athering provisions to enc ourage and facilitate continued injection of CO 2 exclusively for storage when EOR/EGR operations

cease.

7Specifically, the Proposed Rule should be m odified also to al low grandfathering of sections 146.88(e) and (f) (continu ous recording devi ces and down-hole automatic shut-off devices, respectively ) regarding Operations; and Section 146.89(b) and (c) (continuous monitoring and specific yearly tests, respectively) regarding Mechanical Integrity. Existing, operationallycompliant, Class II EOR-wells will continue to protect USDWs, as established by their operational histories, even when inje ction is for the exclusive purpose of CO2 sequestration without the foregoing additional Operation or Mechanical Integrity requirements. In addition, the following sections of the Proposed Rule simply will not be applicable or pertinent at the time of transition because these provisions presume that no in jection has commenced. These sections

are as follows:

• Permit Application § 146.82(g) and (j);

• Area of Review § 146.84 (b)(2 )(iv), (c)(1) and (d);

• Logging Sampling and Testing § 146.87(a), (b) and (f); and

• Testing and Monitoring § 146.90 (b), (d), (g) and (h).

These provisions should not and cannot a pply when a Class II EOR and Storage project transitions to an exclusively st orage project because, as a practical matter, performance of certa in "baseline measurements ," "model predictions," "witnessing of logging and testing," a nd "corrective acti ons" will not be possible prior to in jection of CO2.

In sum, EPA should expand the grandfathe ring provisions to encourage continued storage of CO2 after EOR/EGR operations ha ve ceased. Most of the existing Class II requirements that were appropriate for regulation of EO R and Storage will continue to operate eff ectively and to safeguard USDWs during exclusively storage operations. Finally, appropria tely expanded grandfathering will facilitate optimal utilization of thes e proven oil and gas reservoirs for geologic sequestration of CO2.

CCS in connection with EOR provides a forward-looking energy policy for the United States, as it will significantly re duce CO2 emissions with the added benefit of increasing ener gy security through increased domestic oil production.

Individual Response: EPA agrees that many Class II well s are designed and constructed to withstand exposure to CO2. The final GS rule provi des for the construction of these wells to be grandfathered per §146.81(c), provid ed the owner or operator can demonstrate to the Director that the wells were engineered and constructed to meet th e requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

8EPA disagrees that other requirements (e.g., m onitoring, operational, and AoR requirements) should also be grandfathered. Following re-per mitting of the well as Class VI, many of the unique factors of GS sites (e.g., increased reservoi r pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the pres ence of water) will result in an increased risk profile, warranting the specific requirements in the final GS rule. Following re-permitting as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final GS rule. See the discussion of EPA's final regulatory approach in the preamble to th e GS rule for additional detail on these requirements.

EPA adds that promotion of energy security and a broader energy policy ar e not within the scope of the GS rulemaking. The GS rule focuses on ensuring that, where GS is deployed, it is conducted in a manner that protect s USDWs from endangerment.

Letter ID: 0224 Comment ID: 21671 Letter Lines: 302 to 308 ; 310 to 312

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

Comment: (B) WELLS, MONITORI NG & OPERATIONS

In general, regulations for geologic sequestration should provide for effective storage management by requiri ng the following activities:

- Site characterization that validates th e geological model of the storage site and confirms potential leakage pathways have been identified and evaluated;

- Risk assessment that bu ilds upon the predicted behavior and movement of the

co2 in the reservoir over tim e and confirms that the potential for leakage has been evaluated through site characterization; and

Individual Response: EPA agrees with the commenter. The requirements for geologic site characterization are based on a long standing UI C regulatory framework tailored to address specific risks to USDWs posed by injection. Thes e requirements promote a flexible, risk-based, site-specific approach to charac terizing and permitting a site for GS projects, and are intended to improve understanding of the pr oject as a whole and promote better modeling of the site.

Letter ID: 0224 Comment ID: 21672 Letter Lines: 314 to 318

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

Comment: - A monitoring plan that measures the pe rformance of the highest leakage risk parameters and validates or update s predictive performance models.

The appropriate implementation of these key areas will ensure the safe and secure operation of a geol ogic sequestration project.

9Individual Response: EPA agrees with commenters that developing and following testing and monitoring plans is an important pa rt of assuring that a GS projec t is operating properly and is crucial for the early detection of potential endang erment to USDWs. The final rule retains this requirement.

Letter ID: 0224 Comment ID: 21673 Letter Lines: 320 to 332

Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 146.86)

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

Comment: (1) Importance of Well Integrity

EPA has appropriately recogni zed that wells are a funda mental component of a secure system for the long-term geologic sequestration of CO2. As such, applying appropriate well design, construction & ope rating requirements is critical to the delivery of secure storage. As prev iously discussed, oil and gas operators have nearly four decades of experi ence, 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 woul d be prudent to rely upon this extensive existing regu latory and industry experience and knowledge in setting Class VI requirement s for wells that inject CO2 for long term sequestration.

Individual 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 tailor ed construction requirements fo r Class VI wells at §146.86. For example, the volume of CO2 anticipated to be inj ected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure condi tions 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. Th erefore, Class VI GS reservoir pressures will increase more in comparison to Class II ER dur ing the injection phase of the GS project.

The final GS rule, at §146.81(c), allows the cons truction 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 protec tion 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 fi nal 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-in jection site care and site closur e requirements in the final GS

rule.

EPA is developing guidance on transitioning from Class II to Class VI. The guidance will assist

10Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI transition. The guidance describes the methods ava ilable for the Director to determine the risk posed to USDWs from a GS/ER project, and how th e 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/g roundwater/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 w ithin the injection zone, and that the integrity of the confining zone is not compromised. Some of the opera ting 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, am ong other factors.

Letter ID: 0224 Comment ID: 21674 Letter Lines: 334 to 348

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

Comment: (2) Flexibility in Design of Monitoring Programs and Selection of Technologies

HEI agrees with EPA that monitoring is important. For example, once a site has been selected, appropriate baseline su rveys should be conducted and analyzed prior to commencing operations. During operations and at site closure, appropriate monitoring technologies should be applied to confirm the integrity and effectiveness of the storage site. Ho wever, there is a common misperception that, in order to achieve secure stor age, a large amount of monitoring is required. The United Nations states that "the propor tion of CO2 retained by appropriately selected and managed site s is likely to exceed 99% over 1,000 years." Thus, the key to secure storag e is the appropriate selection and management of the site and these activities should be the focus of any regulatory framework for CO2 geo-sequest ration. If done properly, a selected site will be secure with a monitoring pr ogram that is designed and focused on the particular storage site.

Individual Response: EPA agrees that good site selec tion, modeling, and management are crucial elements of a successful GS project, but disagrees that this is an effective substitute for rigorous site monitoring. EPA also agrees with commenters and believes that flexibility is important in developing and implementing a monito ring plan that is appropriately tailored for a specific GS site. The purpose of the requirement at §146.90 to develop site-specific testing and monitoring plans is to ensure that the monitori ng performed at a site is appropriate for site operational conditions and the geol ogic setting. EPA believes that th is is the best approach for addressing potential risks at GS sites. These flexible provisions in the monitoring requirements for Class VI wells enable the owner or operator to tailor monitoring programs to the specific needs of each project in cons ultation with the Director.

11EPA is developing guidance on testing and mon itoring to assist owne rs or operators and Directors in evaluating requi rements under §146.90, including pr oposed monitoring plans. The guidance describes available technologies a nd recommended approaches for implementing a testing and monitoring plan, including pre-ope rational geophysical l ogging and testing of injection wells, MITs, injecti on well testing during operation, groundwater quality monitoring, tracking the CO2 plume and pressure front, a nd soil gas and surface air monitoring which may be required by the UIC Director for specific GS projects. Th e guidance can be found on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_se questration.cfm.

Letter ID: 0224 Comment ID: 21675 Letter Lines: 350 to 373

Comment Code: 1840 1.4.1.3 Other research

Comment Code: 4655 2.6.5.1 Plume tracking techniques/ geophysical methods (seeking comment)

Comment: HEI and its affiliated companies in BP have significant and highly relevant experience around monitoring of the subs urface and the surface. For many decades, BP has been effectively employi ng a number of monitoring technologies to ensure the safety and integrity of its customary oil and gas operations, including CO2 EOR-related operations sin ce the 1970’s in West Texas and Alaska. Notably, since 2004 BP has been operating the In Salah, Algeria, CO2 storage project where BP (and partners) has been storing around 1 million tones CO2 per year in a deep saline formation close to a producing gas field. The In Salah CO2 Storage project also incorporates a re search project to test CO2 storage monitoring technologies with a program that is much more extensive than would be appropriate for a commercia l project. At In Salah, BP is testing new technologies (such as satellite imagery and micro-seismic) and conventional oilfield technologies (such as tracers and conventional 3D seismic) to compare

and contrast results as the partnership endeavors to design and develop monitoring technologies and methodologies th at are reliable and cost-effective, given the expectation of futu re commercial application.

Before initiating inje ction at In Salah, BP conduc ted a thorough assessment of potential leakage paths at the site; BP then tailored the monitoring program to address those site-specific risks. Ther e are two other monitored, industrialscale CO2 injection projects in the wo rld (at Sleipner and Weyburn) and the site-specific nature of monitoring requir ements is demonstrated by comparing these three CO2 storage projects - monito ring that works well at one location may not work at all in another location.

Individual Response: EPA continues to track ongoing field and laboratory research into all aspects of GS, including subsur face CO2 monitoring. The Agency is tracking the operations and technical developments of more th an three dozen small- and large-scale GS injection projects in the US and abroad. Also, since field experien ce and well construction, injection, and monitoring information relevant to GS comes from operations that inject acid gas or inject CO2 for ER, the Agency has conducted evaluations regarding these commercial field operati ons and continues to

12track GS-relevant developments in these commercial operations.

Additionally, EPA ORD's National Center for En vironmental Research (NCER) awarded six Science To Achieve Results (STAR) grants in the Fall of 2009 to re cipients from major

universities and instituti ons within the scope of "Integrate d Design, Modeling and Monitoring of Geologic Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water." In one project, the University of Texa s at Austin will assess appropriate monitoring approaches at geologic sequestration sites.

Regarding the development of monitoring and te sting plans, EPA believes that testing and monitoring plans should be based on site-specific information, similar to the examples described by the commenter, and believes that flexibility is important in developing and implementing a monitoring plan that is appropr iately tailored for a specific GS site. The purpose of the requirement at §146.90 to develop site-specific testi ng and monitoring plans is to ensure that the monitoring performed at a site is appropriate for site operat ional conditions and the geologic setting. EPA believes that this is the best approach for addressi ng potential risks at GS sites. These flexible provisions in the monitoring requirements for Class VI wells enable the owner or operator to tailor monitoring programs to the speci fic needs of each project in consultation with

the Director.

The final regulation provides for flexibility in: 1) methodologies used to co llect these data, 2) the spatial resolution at which the data should be co llected, and 3) how often the data should be collected. The number and placement of monitoring wells will be based on site-specific information such as the calculated AoR, inject ion rate and volume, site geology, baseline data, and the presence of artificial penetrations within the AoR. In some instances, there may be a limited number of options for complying with EPA's minimum requirements. For example, monitoring for geochemical changes will require use of monitoring wells and collection of groundwater samples for chemical analysis. Many options currently exis t for complying with other requirements, such as tracking the positio n of the plume and pressure front within the injection zone.

Flexibility is also provided re garding how to monitor for the sp ecific data required by the final rule. The testing and monitoring plan is develope d by the owner or operato r in consultation with the Director and is designed to ensure that a detailed, Director-approved document describing how monitoring will be conducted during the lifetime of the project exists. EPA is developing guidance on testing and monitoring to assist owners or operators and Directors in evaluating requirements under §146.90, including proposed monitoring plans. The guidance describes available technologies and reco mmended approaches for implem enting a testing and monitoring plan, including pre-operational geophysical logging and testin g of injection wells, MITs, injection well testing during ope ration, groundwater quali ty monitoring, tracking the CO2 plume and pressure front, and soil gas and surface ai r monitoring which may be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0224 Comment ID: 21676 Letter Lines: 375 to 381

13Comment Code: 1250 1.1.1.4 Flexibility is needed (p erformance-based standards)

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

Comment: With respect to monitoring requirements in general, EPA should adopt regulations that are performance and risk-based and will result in a site-specific monitoring program that is designed to understand the location, movement and stabilization of the CO2 plume in th e subsurface as well as the early identification of any leakage for appropr iate corrective action. HEI commends EPA for its efforts in this regard, but believes that further modification is necessary. HEI agrees with the proposal to allow a phased approach to conduct

Individual Response: EPA agrees with commenters and believ es that flexibility is important in developing and implementing a monitoring plan that is appropriately tailored for a specific GS site. The purpose of the requirement at §146.90 to develop site-specific testing and monitoring plans is to ensure that the monitoring performe d at a site is appropria te for site operational conditions and the geologic setting. EPA believes th at this is the best approach for addressing potential risks at GS sites. These flexible provisions in the monitoring requirements for Class VI wells enable the owner or operato r to tailor monitoring programs to the specific needs of each project in consultation with the Director.

The final regulation provides for flexibility in: 1) methodologies used to co llect these data, 2) the spatial resolution at which the data should be co llected, and 3) how often the data should be collected. The number and placement of monitoring wells will be based on site-specific information such as the calculated AoR, inject ion rate and volume, site geology, baseline data, and the presence of artificial penetrations within the AoR. In some instances, there may be a limited number of options for complying with EPA's minimum requirements. For example, monitoring for geochemical changes will require use of monitoring wells and collection of groundwater samples for chemical analysis. Many options currently exis t for complying with other requirements, such as tracking the positio n of the plume and pressure front within the injection zone.

Flexibility is also provided re garding how to monitor for the sp ecific data required by the final rule. The testing and monitoring plan is develope d by the owner or operato r in consultation with the Director and is designed to ensure that a detailed, Director-approved document describing how monitoring will be conducted during the lifetime of the project exists. EPA is developing guidance on testing and monitoring to assist owners or operators and Directors in evaluating requirements under §146.90, including proposed monitoring plans. The guidance describes available technologies and reco mmended approaches for implem enting a testing and monitoring plan, including pre-operational geophysical logging and testin g of injection wells, MITs, injection well testing during ope ration, groundwater quali ty monitoring, tracking the CO2 plume and pressure front, and soil gas and surface ai r monitoring which may be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

14Letter ID: 0224 Comment ID: 21677 Letter Lines: 381 to 382

Comment Code: 3630 2.2.4.1 Comments in favor of allowing phased corrective action

Comment: necessary. HEI agrees with the proposal to allow a phased approach to conduct

corrective action in an Area of Review th at has pre-existing well penetrations.

Individual Response: EPA acknowledges the commenter’s s upport of phased corrective action and agrees that phased corrective action may provide many benefits to a project including, but not limited to, spreading the burden of cost, avoi ding delays in project start-up, allowing for use of future, improved corrective act ion techniques and addressing unanticipated changes in the movement of the CO2 plume or pressure front . EPA believes that the phased corrective action approach is appropriate for GS projects, and retained it at §146.84(b)(2)(iv) in the final GS regulation.

Letter ID: 0224 Comment ID: 21678 Letter Lines: 383 to 388

Comment Code: 3200 2.2 Proposed Area of Review and Corrective Action Requirements (40 CFR 146.84)

Comment: Existing wells within the AoR may be ideal candidates for conversion to monitoring or injection wells during the life of the project and, therefore, should not be plugged and abandoned prior to injection. Existing wells within the likely plume area that are not plugge d and abandoned should have diagnostic testing to ensure there is minimal risk of vertical leakage prior to conversion to monitoring or injection status.

Individual Response: EPA recognizes that operators may choos e to convert existing wells in the AoR for use as monitoring wells or injection well s. An operator seeking to use an existing well as a monitoring well would need to describe th at well in the proposed testing and monitoring plan to demonstrate that is appropriately constr ucted for use as a monitoring well and compatible with the GS injection operation and injectate. The Director woul d take the condition of the well into consideration in approving the pr oposed testing and monitoring plan.

Letter ID: 0224 Comment ID: 21679 Letter Lines: 390 to 398

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

Comment: Furthermore, in various parts of th e Proposed Rule, EPA has prescribed particular monitoring technologies. Ma ndating any specific technology(ies) would have the adverse effect of (1) pr omoting particular t echnologies to the exclusion of other developed - and to be developed - technology(ies), and (2) substantially increasing costs withou t necessarily contributing to the protection of USDWs. This would hinder th e development and deployment of CCS at commercial scale. Moreover, it would discourage the development of other

15technologies. HEI therefore strongly discourages EPA from promulgating regulations that mandate the use of any specific monitoring technology.

Individual Response: EPA agrees that prescribing specific technologies to be used in all cases for GS would not be appropriate given the variability in sites, and believes that the rule provides flexibility to owners or operators to develop site-specific testing a nd monitoring plans that employ appropriate technologies provided th ey meet the requirements at §146.90. EPA is developing guidance on testing and monitoring to assist owners or operators and Directors in evaluating requirements under §146.90, including proposed monitoring plans. The guidance describes available technologies and recommen ded approaches for implementing a testing and monitoring plan, including pre-ope rational geophysical logging and testing of injection wells, MITs, injection well testing during operation, gr oundwater quality monitoring, tracking the CO2 plume and pressure front, and soil gas and surf ace air monitoring which may be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequestration.cfm. In addition, in January 2009, DOE published a best practices manual entitled "Monitoring, Verificat ion, and Accounting of CO2 Stored in Deep Geologic Formations" (DOE/NETL-311/081508); this manual is included in

the docket for the for the final GS rule.

Letter ID: 0224 Comment ID: 21680 Letter Lines: 400 to 445

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)

Comment: (3) Specific Comments

In addition to the foregoing, HEI respectfully submits the following areas of specific comment:

(i) Well Design and Construc tion To Avoid Corrosion

One area of comment requested by EPA relate s 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 US DWs. Risk Profile of a CO2 Geological Storage Project: Wells, by Christopher, Crow, Dodds, Wright, Williams, March

2008.

HEI strongly discourages EPA from setti ng a requirement to use degradationresistant materials & cement. Actual fi eld 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 cem ent alteration rates due to curing and exposure conditions, but neither supports the requirement for the use of

16degradation-resistant materials and cemen t because the laboratory procedures that were used do not necessarily re present 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 inform ation, 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 Captur e Project, 2008). Both of these field studies identified that hydraulic isola tion was maintained across the caprock, and the majority of cement reaction was localized to the area near the CO2

interval. Field results indi cate 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 casi ng is the primary means of achieving this objective.

Based on the foregoing, degradation-resistan t materials should not be mandated for all projects, without regard to site -specific characteristics. Rather, the application of degradati on-resistant materials & cement, if any, should be defined on site-specifi c characteristics.

Individual Response: The rule does not specify the material s 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 selecti on 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 spec ified at §146.82 (a)(12), that demonstrate that the well as constructed will prev ent unacceptable fluid movement; allow the use of appropriate testing devices and workover tools; and allo w 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 a bout 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.

Letter ID: 0224 Comment ID: 21681 Letter Lines: 447 to 456

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

17Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)

Comment: HEI strongly supports, with one modificat ion discussed below, EPA’s actual language of the Proposed Rule in sec tion 146.86(b)(5), whic h 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 flui ds 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 perfor mance-based approach set forth in the Proposed Rule.

Individual 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 flui ds and of sufficient quality and quantity to maintain integrity over the design life the GS project. Both field and laboratory studies ha ve found acid alteration

where traditional well cements have been used for CO2 injection. Although the laboratory and field studies suggest that co rrosion problems may not be seve re, such problems cannot be conclusively ruled out, and the amount of availabl e 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 clea r consensus at this time on the corrosion risks for the steel components of injecti on 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 requireme nt 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 de sign 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.

Letter ID: 0224 Comment ID: 21682 Letter Lines: 458 to 467

Comment Code: 3820 2.3.1 Well construction procedures

Comment: Furthermore, section 146.86(b)(5) should be amended to base the choice of casing and cement materials on the planned opera ting life of the well as opposed to the ultimate duration of the geologic sequestr ation 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 corrosi on-resistant material , if an extra

18level of mitigation were deemed nece ssary 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).

Individual Response: EPA disagrees that the casing, cement or other materials should only be designed for the period of the injection process, ra ther than the life of the sequestration project. GS projects are anticipated to ha ve long life spans in comparison to other types of deep injection wells. Not only must Class VI wells be able to function safely and properly over the lifespan of the GS project, but they must be constructe d such that USDWs remain protected after well plugging. The requirements at §146.86 will ensure that the well can maintain integrity throughout the proposed life span of the project, including after the injection well is plugged and through post-injection site care period and beyond. While the risk profile of a GS site will decrease following cessation of in jection, EPA believes that Class VI wells must be designed to protect USDW from endangerment for the life of the project. Fu rthermore, rigorous casing and cementing help ensure that the Class VI well will not serve as a conduit fo r movement of fluids

associated with future injection operations.

Letter ID: 0224 Comment ID: 21683 Letter Lines: 469 to 483

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

Comment: (ii) Horizontal Wells Should Be A pproved for Geologic Sequestration

HEI agrees with EPA’s discussion regard ing the usefulness a nd 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 w ith 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 thic k 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 th ree 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 we lls 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 caproc k. There are other options to optimize

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

19Letter ID: 0224 Comment ID: 21684 Letter Lines: 483 to 486

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

Comment Code: 4130 2.4.1.3 Appropriateness of using fractur ing for well stimulation (seeking comment)

Comment: number of penetrations through the caproc k. There are other options to optimize injectivity as well that include, but should not be limited to, hydraulic fracture treatments, multiple injection points along the wellbore and open hole completions.

Individual Response: EPA agrees that hydraulic fracturi ng is one of several stimulation technologies available to improve wellbore and formation injectivity. The final rule allows the use of hydraulic fracturing at GS site s, if approved by the Director.

EPA clarifies that all stimulati on for Class VI wells, includi ng hydraulic fracturing, must be approved by the Director. Owners or operators must submit a proposed stimulation program as part of the permit application under §146.82(a)(9 ); the plan must de monstrate that any stimulation activities will not compromise the inte grity of the confining zone. The Director will evaluate the owner or operator's proposed stimula tion 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 opera tions (§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 dur ing injection or stimulation.

EPA also agrees that multiple and open hole completions are also acceptable manners to improve injectivity. Class VI wells with these types of completions are acceptable, provided all other construction requirements at §146.86 are met.

Letter ID: 0224 Comment ID: 21685 Letter Lines: 488 to 507

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

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

Comment: (iii) Long String Casing Is Not Needed

Section 146.86(b)(3) states that "at le ast one long string cas ing . . . 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 constrai n the ability to undertake future potential well interventions that su pport downhole monitoring and well remediation, if such become necessary.

20To avoid such an unintended result, HEI recommends that EPA not mandate the placement of an isolation casing string fr om the surface, but rather allow the casing string to extend from beneath th e surface or otherwise based upon site

characteristics. Cement should cover th e uppermost caprock (within the Area of Review) by approximately 500 feet; cement c overage 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 uni que in the geological intervals of the caprock(s), injection zone(s) and positi on 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 capro ck, as discussed above.

Individual Response: EPA does not believe that the cem enting 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 an d allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information.

Additionally, EPA is developing guidance on the constr uction 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: 0224 Comment ID: 21686 Letter Lines: 509 to 528

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment: (iv) Definition of Ca rbon Dioxide Stream

Section 146.81 of the Proposed Rule define s "carbon dioxide stream" as follows:

Carbon dioxide stream means carbon dioxide that has been captured from an emission source (e.g., a power plant), plus incidental associated substances

derived from the source materials and th e capture process, and any substances added to the stream to enable or improve the injection process. This subpart does not apply to any carbon dioxide str eam that meets the definition of a hazardous waste under 40 CFR part 261.

By limiting the definition to "emission s ources," the Class VI regulations may have the unintended effect of narrowing th e types of sources that might inject CO2 for geologic sequestration. The particular source of the CO2 is not material in terms of protecting USDWs. Furthermor e, the Final Rule should not address the source because it is beyond the scope of this regulation. We recommend

21deleting the phrase “has b een captured from an emission source (e.g., a power plant)” from the definition contained in section 146.81 of the Proposed Rule so

that the Final Rule does not inadverten tly preclude other non-emission sources

of CO2.

Individual Response: EPA disagrees with the suggested edit. The final definition of carbon dioxide stream at §146.81(d) remains unchanged and reads as follows: “[C]arbon dioxide that has been captured from an emission source (e.g., a power plant), plus in cidental associated

substances derived from the source materials a nd the capture process, and any substances added to the stream to enable or improve the injecti on process. This subpart does not apply to any

carbon dioxide stream that meets the definiti on of a hazardous waste under 40 CFR part 261.”

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

Letter ID: 0224 Comment ID: 21687 Letter Lines: 530 to 545

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

USDW

Comment: (v) EPA Should Not Restrict Inject ion To Below Lower-Most USDW

The Proposed Rule restricts injection of CO2 to below the lowermost USDW. (See §§ 144.6(f), 146.5(f) and 146.81.) EPA acknowle dges that such a restriction would preclude the consideration and use of various potential storage sites, and has requested comment on this approach.

HEI disagrees with such a blanket restri ction, one that would pose a barrier to many, viable storage sites. The imposition of an artificial constraint limiting injection only to reservoirs below the USDW is not justified by technical knowledge or historical indus try experience. For example, Class II requirements have proven successful in protecting USDW s even though injection into certain

reservoirs has occurred above the lower-m ost USDW. Given the EPA’s effort in adopting a general performance-based appr oach, injection shoul d be allowed to proceed into acceptable reservoirs provide d the reservoir is demonstrated to provide secure CO2 storage above an d below the injection formation.

Individual Response: EPA acknowledges that there are lim ited circumstances where injection above the lowermost USDW can be performe d in a manner that protects USDWs from endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which owne rs or operators can seek a waiv er of the Class VI injection depth requirements for inject ion into non-USDW formations above and/or between USDWs. Additionally, the final GS rule doe s not categorically preclude or prohibit injection into any type

of formation.

22EPA believes that these requirements will ensure USDW protection while providing flexibility to UIC program Directors and owne rs or operators who undertak e CO2 injection for GS. The Agency believes this approach: 1) responds to co ncerns about local and re gional geologic storage capacity limitations imposed by th e proposed injection depth require ments; 2) allows for a more site-specific assessment of injection depth for GS projects; 3) accommodates injection into different formation types; 4) a llows for injection of CO2 for GS into non-USDWs above and/or between USDWs when appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to concerns about the use of aqui fer exemptions for GS. Finally, EPA’s approach to addressing injection depth va riability through a waiver process responds to concerns about future drinking wa ter resource availability and the need to ensure that high quality water remains available in sufficient qua ntities to supply drinking water needs. For additional information on the waiver approach, pleas e see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0224 Comment ID: 21688 Letter Lines: 547 to 554

Comment Code: 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth

Comment: A containment system with a ppropriate site characterization, risk assessment and monitoring is the key to secure storage and protection of USDWs. Proximity of the injection zone to USDWs (i.e. whet her shallower or deeper) is not the appropriate criteria for pr otection of USDWs because pr oximity alone does not materially impact risk of leakage. Sim ilarly, EPA should not establish minimum depths for CO2 injection. Instead, any c onstraints placed on injection should be site-specific, consistent with the cont ainment and capacity parameters of the storage site in question.

Individual Response: EPA agrees that it is not appropriate to set a mi nimum injection depth for GS projects and the Agency believes that a determ ination of site-suitabili ty for GS (i.e., that

subsurface formations will receiv e and confine injected CO2) s hould be made on a site-specific basis. The GS rule, at §146.82, requires the owne r or operator to provide extensive site- and project-specific information to the Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be contai ned within the injection formation, and that USDWs will be protected from endangerment.

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

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

23and preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0224 Comment ID: 21689 Letter Lines: 556 to 561

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

Comment: Related to the depth of in jection, 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 su rface." One reason is that at certain potential storage sites USDWs may be locate d at depth; consequently, it would be technologically infeasible to construct surface casing to the requisite depth prescribed by the Proposed Rule.

Individual Response: The final GS rule at §146.86(b)(2) requires that surf ace 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 ow ner 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 regardi ng construction of Class VI wells where the lowermost USDW is very deep. To further address comments on d eep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells opera ting under injection depth waivers must comply with additional construction require ments to ensure that wells used to inject above or between USDWs are protective. See the discussion of the wa iver approach in the preamble to the final GS

rule for additional information.

EPA stresses that protection of USDWs from en dangerment, 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. A ny 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 unde r UIC requirements or the SDWA.

Letter ID: 0224 Comment ID: 21690 Letter Lines: 563 to 566

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

USDW

Comment Code: 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth

Comment: In summary, EPA should not mandate a re quirement of injection only below the lower-most USDW nor a minimum depth for in jection of CO2. Such a comprehensive prohibition would unjustifiabl y exclude potential storag e sites that do not pose

24an endangerment to USDWs.

Individual Response: EPA agrees that it is not appropriate to set a mi nimum injection depth for GS projects and the Agency believes that a determ ination of site-suitabili ty for GS (i.e., that

subsurface formations will receiv e and confine injected CO2) s hould be made on a site-specific basis. The GS rule, at §146.82, requires the owne r or operator to provide extensive site- and project-specific information to the Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be contai ned within the injection formation, and that USDWs will be protected from endangerment.

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

formations above and/or between USDWs. The waiver approach requires the submission of extensive, site-specific information (in conjunc tion with the permit appl ication submission) to demonstrate that injection of CO2 into a non-US DW that is above or between USDWs can be done in a manner that is protective of USDWs. Th e requirements are designed to ensure that the owner or operator, the Director, and the Regional Administrator cons ider, on a site specific basis, the implications, benefits, and challenges associat ed with GS and ensuring water availability and USDW protection. For additional information on the waiver approach, please see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0224 Comment ID: 21691 Letter Lines: 568 to 581

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

Comment: (vi) Injection Well Operation & Mechanical Integrity Requirements

Consistent with the earlier discussion about blanket construction limitations, HEI also disagrees with universal manda tes regarding certain CO2 injection operations. EPA should not include auto matic downhole shut-in devices as a standard requirement for CO2 injection wells (section 146.88(e)). An across-theboard requirement for installation of downhole devices is excessive - unsupported by technical knowledge and indus try experience - and would impose unnecessary costs. Overpressure prot ection is best achieved by ensuring compatibility of the casing/tubing material design strength with the surface injection (compression) syst em. Downhole shut-in devices may be appropriate, however, for site-specific situations (suc h as offshore), but they should not be mandated for all storage sites. Rather, the requirement of downhole shut-in

devices should be left to th e discretion of the Director.

Individual Response: After evaluating the risks and benefi ts of down-hole shut-off systems and considering additional research, EPA will not re quire automatic down-hole shut-off devices for onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from

25endangerment. Instead, the final rule, at §146.88(e)(2 ), requires that owne rs or operators of

onshore Class VI wells install automatic surface shut-off devices. The rule affords Director's

discretion to mandate automatic down-hole shut -off devices in onshore situations that may warrant their use. EPA believes that requiring the installation of au tomatic surface shut-off devices for onshore wells (and affo rding Director's discretion to require down-hole devices where necessary) ensures that proper precautions ar e taken to prevent subs urface fluid movement and ensure protection of USDWs, hu man health, and the environment.

The GS rule, at §146.88(e)(3), requ ires the installation of down- hole shut-off devices for Class VI wells located in the offshore submerged lands within the jurisdiction of a State UIC program. The Agency believes that the unique constructio n and operational conditions for offshore Class VI wells, including isolation from shorelines and the need to c onstruct wells through the water column and the subsurface, may delay response time in the event of well difficulties. These conditions merit requiring automatic down-hole shut-off devices for offshore wells in the submerged lands of a State.

While EPA acknowledges that the likelihood of damage to onshore f acilities is lower than that for off-shore facilities, down-hole shut-off valv es are still commonly used in onshore facilities such as acid gas injection wells and high pressu re, high-temperature wells. While valve failure is a concern, EPA believes that technology has advanced sufficiently to make valve failure a rare occurrence and to appropriately handle such failure if it occurs so that USDWs will not be endangered. For example, wireline retrievable devices can allow repair or replacement of damaged devices without necessitating pulling the tubing.

EPA believes that requiring the in stallation of automatic surfac e shut-off devices for onshore wells (and affording Director's discretion to requir e down-hole devices where necessary) and

automatic down-hole shut-off devices for offsho re wells in submerged lands within the jurisdiction of a State ensures that proper pre cautions are taken to prevent subsurface fluid movement and ensure pr otection of USDWs.

Letter ID: 0224 Comment ID: 21692 Letter Lines: 583 to 591

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

Comment: With regard to validating mechanical integrity of CO2 injection wells, HEI generally agrees with EPA’s suggestion to evaluate the "absence of significant leaks" by monitoring at some regular frequency the injection pressure, flow rate, injected volumes and the annul ar pressure. (See §146.89 (b).) An alternative method for determining mechan ical integrity, as noted by EPA, is periodic pressure testing; this should re main an option for site-specific cases. Where periodic pressure testing is implemented, the pressure should be considered by evaluation of the formati on potential instead of casing burst or tubing collapse limit.

Individual Response: EPA believes that continuous pressure monitoring to demonstrate internal

26mechanical integrity as required under §146.89(b) is preferable to periodic pressure testing as a means of demonstrating internal MI. The combination of comput er-driven continuous pressure monitoring linked to an automa tic injection shut-off system provides maximum protection to USDWs from endangerment and is the earliest warn ing to owners or oper ators that well repairs need to be performed. EPA believes that the te chnology for continuous monitoring is available, is currently in fairly wide use. The Texas Cla ss I well regulations for industrial wells currently require continuous monitoring of annulus pressu re and volume and the majority of injection wells in Ohio conduct continuous monitoring (G WPC, 2006). At least one commenter indicated that the technology required for continuous monitoring is curren tly available and should not present an undue cost burde n. Continuous annulus monitoring is also conducted at the commercial-scaled carbon capture and geologic seque stration operation at the In Salah, Algeria natural gas plant where more than 3 million tons of CO2 have been sequestered since 2004.

EPA is using an adaptive approach to regulati ng GS. The Agency plans to collect and review data every six years on early GS projects, in cluding MIT data, to determine whether the appropriate amount and types of information a nd appropriate documentation are being collected,

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

Letter ID: 0224 Comment ID: 21693 Letter Lines: 593 to 598

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

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

Comment: The frequency of the monitoring should be defined not as "continuous" but as "regular" or "periodic" based upon si te characteristics because regular monitoring (e.g., every minute or hour) will often be adequate. For example,

fluid volume in the annulus is static and requires evaluati on of a pressure pulse to determine the depth of top of fluid. Therefore, this should be monitored on a monthly or quarterly ba sis to support the pressure data.

Individual Response: EPA believes that continuous pressure monitoring of GS wells, instead of periodic testing, which is required for most othe r types of deep injecti on wells is appropriate because the potentially corrosive nature of CO 2 injectate streams in the presence of water

enables the immediate identificati on of corrosion-related internal mechanical inte grity problems that could lead to significant well problems and failure. Continuous monitoring was found to be very important in an EPA study of UIC Class I internal MIT failure rates and causes (USEPA 1993). The study reviewed MIT results over a 5 year period and found 135 MIT failures in 428 wells (a single well can have more than one MI T failure). In all cases, the MIT failures were found through continuous annulus monitoring whic h served the important role of an early warning to prevent any well failure. Class VI in jection wells must be equipped with dedicated computer-based continuous pre ssure monitoring devices in con cert with the shut-off systems required for GS wells, which typically take read ings several times per second and record them electronically in a computer system. 40 CFR §146.91( a)(2) requires that mont hly averages of the continuous annulus monitoring be re ported on a semiannual basis.

27EPA believes that monitoring of annulus fluid volu me is an important method for verifying that the well system is intact, and knowing the annul us fluid volume is necessary for monitoring annulus pressure. While this requirement has un til now been limited to Class I hazardous waste injection wells, the high volumes and supercriti cal nature of the injectate, the potential geomechanical stresses in the wellbore, and th e potential for movement of the buoyant CO2 in the event of a MI loss make it an important sa fety consideration for GS projects. Continuous pressure monitoring allows immediate identificat ion of corrosion-related well integrity loss. EPA agrees with the commenter that recording annulus fluid volume ma y not be appropriate. However, EPA believes that knowing annulus flui d volume required at § 146.88(e) is a necessary component of monitoring well mechanical integr ity, but believes that knowing the annulus fluid

volume added is sufficient to meet the intent of the requirement. The final GS rule requires that owners or operators use conti nuous recording devices to monito r injection pressure, rate and volume; as well as the pressure on the annulus between the tubing and th e long string casing. It also modifies the requirement in the proposed rule to continuously monitor annulus fluid volume; it now requires recording of annul us fluid volume added §§146.88(e); 146.89(b); and 146.90 (b).

Fluid level can be detected using acoustic t echniques (Schubert, 1998). The Texas Class I well regulations for industrial wells currently require continuous monitoring of annulus pressure and volume, and the majority of injection wells in Ohio conduct continuous monitoring (GWPC, 2006). At least one commenter indicated that the technology required fo r continuous monitoring is currently available and should not presen t an undue cost burd en. Continuous annulus monitoring is also conducted at the commercial-scaled carbon capture and geologic sequestration operation at the In Salah, Algeria natural gas plan t where more than 3 million tons of CO2 have been sequestered since 2004. The technology for con tinuous monitoring is available, is currently in fairly wide use, and the costs are not burdens ome, especially given the operational and safety

considerations addressed.

Letter ID: 0224 Comment ID: 21694 Letter Lines: 600 to 603

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment)

Comment: Section 146.89(c) lists specific methodologi es to monitor fluid movement. HEI strongly disagrees with the requirement of any particular methodology because this would limit technology development and favor certain technologies to the

exclusion of others without any rationale basis.

Individual Response: EPA believes that the MITs describe d in the rule at §146.89 are effective methods and have been used successfully by injection well operators for decades and provide an important early warning of potential pr oblems in the injection well system.

EPA clarifies that the regulations provides the Director discreti on to require additional methods or, with the Administrator's approval, to appr ove the use of alterna tive MIT methods based on specific information about the s ite or the well. See §146.89(e).

28In addition, EPA is using an adaptive approach to regulating GS. The Ag ency plans to collect and review data every six years on GS projects to determine whether the appropriate amount and types of information and appropriate documenta tion are being collected, and to determine if modifications to the requirements are appropriate or necessary. EPA believes this flexibility and the adaptive approach will allow the incorporation of future technologies.

Letter ID: 0224 Comment ID: 21695 Letter Lines: 605 to 622

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

Comment: (C) SITE CLOSURE PERIOD

EPA correctly states in its Preamble that defining the post-in jection site care period is "difficult to define becau se it is based on site-specific considerations." (73 Fed. Reg. at 43519.) The three studies cited by EPA also

concluded that "the actual time for CO2 plume stabiliziation . . . will be very site-specific, being influenced by ge ologic factors such as formation permeability, geochemistry, and the degree of capillary trapping." (Id.) However, the Proposed Rule establishes a default 50-year pe riod (following the cessation of injection) during which the operator must conduct monitoring to

demonstrate that "the car bon dioxide plume and pressure front have stabilized and the geologic sequestration project does not pose an endangerment to USDWs." (See § 146.93(b).) The designation of a 50y ear time-period without regard to particular site characteristics is ar bitrary and not suppor ted by existing

scientific studies or indus try experience. Moreover, the 50-year timeframe does not provide any incremental benefit as comp ared with a performance standard to protecting USDWs; rather, it will be a significant deterrent to commercial investment in geologic se questration projects.

Individual Response: EPA disagrees that the 50 year time frame is unsupported. In determining the post-injection site care-ti meframe for the proposed regulation, EPA reviewed industry reports, existing environmental programs, and in itial GS research studies. EPA provided a synthesis of pertinent results from GS mode ling studies in the preamble to the proposed regulation. Further explanation of this analys is was included in an EPA-prepared background

document that is available in the federal docke t, titled "Computational Modeling of Underground Injection of Carbon Dioxide for Determinati on of Area-of-Review and Potential Risk to Underground Sources of Drinking Water." Based on review of these studies, modeling results indicate that the CO2 plume st abilization may occur on the time frame of 10-100 years after the cessation of injection. EPA believes that a 50-year default post-injection s ite care timeframe is a reasonable midpoint for most GS projects and available data, including data submitted by commenters, do not support a different default ti meframe, and has retained this in the final regulation.

However, EPA recognizes that there may be site s where the 50 year post injection site care

29timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. For this reason, the GS rule o ffers owners or operators flexibility regarding

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

EPA believes however, that to ensure USDW protection from enda ngerment, a default timeframe for post-injection site care will be necessary in al l but a limited number of cases. This default 50 year post-injection site care ti meframe represents a reasonable and protective monitoring period based on a review of research studies, industr y reports, and existing environmental programs, and evaluation of public comments.

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

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

Letter ID: 0224 Comment ID: 21696 Letter Lines: 624 to 634

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

Comment Code: 5260 2.8.2.3 Adjusting the post-injecti on timeframe (seeking comment)

Comment: HEI urges EPA to adopt the performance st andard that EPA considered in its review. EPA considered three options: (1) fixed period; (2) performance standard; and (3) combination of fixed period and performan ce standard; EPA states it adopted the latter appro ach. (73 Fed. Reg. at 43519.) While the Proposed Rule allows a Director to re duce the 50-year minimum (§146.93(b)(2)), the practical effect will be the 50-year timeframe applies unless an operator is able to overcome the presumption built in to the Proposed Rule that 50 years is adequate. Indeed, this is more prescrip tive than the requirement for Class I hazardous wells, which provides that the ti meframe for post-injection site care ends when the plume has stabilized a nd cannot endanger USDWs. (Id.; 40 CFR §146.71.)

Individual Response: EPA agrees that some owners or operat ors will be able to demonstrate, in less than 50 years, that the pr essure front and plume no longer pose a risk of endangerment to USDWs. However, based on studies, EPA believes that the 50 year default time frame is

warranted based on additional review of research studies and reports an d evaluation of public

comments.

30However, EPA recognizes that there may be site s where the 50 year post injection site care timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. EPA believes that the best wa y to address all possibi lities, while ensuring USDW protection from endangerment, is to se t a 50 year default post-injection site care timeframe, with flexibility to: (1) allow the Direct or discretion to shorten or lengthen the PISC timeframe during the PISC period based on site -specific data, pursuant to requirements at §146.93(b); or (2) afford the Direct or discretion to allow a Class VI well owner or operator to demonstrate, based on substantial data during th e permitting process, that an alternative PISC timeframe may be appropriate if it ensu res non-endangerment of USDWs pursuant to requirements at §146.93(c).

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

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

Letter ID: 0224 Comment ID: 21697 Letter Lines: 636 to 663

Comment Code: 5260 2.8.2.3 Adjusting the post-injecti on timeframe (seeking comment)

Comment: EPA should adopt the performance-based stan dard that it considered previously. Accordingly, the post-injection site care period ends when m onitoring and other site-specific data demonstrate that th e geologic sequestrati on project does notpose an endangerment to USDWs. (See e.g., 73 Fed. Reg. 43520.) A performancebased approach is consistent with te chnical knowledge and historic industry experience. The site closure period would be appropriately ba sed on particular

site characteristics and historic site performance. For example, a wellselected and -managed sequestration site (such as an existing oil or gas field) that has met its performan ce objectives (including plum e stabilization) will be

much more secure and could be closed reas onably quickly (poten tially, in as few as 2-3 years). At other sites that ar e less well confined (e.g., deep saline formation without a conventional 4-way cl osure), the CO2 could move around for some time even after injection ceases before stabilizing, and might therefore require a longer period to allow for additional residual and solubility trapping.

In summary, HEI recommends that EPA a dopt a performance-based approach to

determine the timeframe for site closure. We also support the site closure

standard offered in the MSDG Proposal for section 146.93(b), which sets forth

detailed criteria that must be satisfied to demonstrate that the site does not pose an endangerment to USDWs. The advantage of the MSDG Proposal as opposed to

31a fixed period is it establishes clea r criteria that an operator must demonstrate before obtaining site cl osure based upon particular site characteristics and is, therefore, reasonabl e applicable to any storage site as opposed to a standard based upon a fixed- duration. The current proposal of 50- years minimum, even subject to potential reduction, w ould result in significantly discouraging the deployment of this t echnology at commercial scale without providing measurable a dditional protection of USDWs.

Individual Response: EPA agrees that there will be circumst ances where it can be demonstrated in less than 50 years that the plume and pressure front no longer pose a risk of endangerment to USDWs. For this reason, the GS ru le offers owners or operators flexibility regard ing the duration of the PISC timeframe by: (1) allowing the Direct or discretion to shorten or lengthen the PISC timeframe during the post-injecti on period based on site-specific da ta, pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator to demonstrate, during the permitting process based on substantial data, that an alternative PISC timeframe may be appropriate if it ensu res non-endangerment of USDWs pursuant to requirements at §146.93(c).

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

comments.

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

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

EPA adds that the purpose of the GS rule is not to incentivize the use of GS; rather, the purpose of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.

Letter ID: 0224 Comment ID: 21698 Letter Lines: 665 to 678

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

Comment: (D) EPA’s Proposed Financial Responsib ility Demonstration Requirements

The proposed financial assurance requiremen ts for Class VI UIC wells require the owner or operator to establish fina ncial responsibility (or "financial

32assurance") to cover the costs of plug ging and abandoning injection wells, as

well as the costs of correc tive action, post-injection site care, site closure and emergency and remedial responses. (73 Fed. Reg. at 43537; §146.85.) The financial responsibility requirements shoul d be consistent with the need to protect USDWs, while being reasonable and cost-effective, yet facilitating geologic sequestration of CO2. We support EPA’s proposed approach that allows for a wide range of financial assurance mech anisms to be utilized to demonstrate financial responsibility. We also suggest that EPA adopt a flexible, iterative approach to financial assurance in keep ing with the phased, adaptive management philosophy of other aspects of the Proposed Rule.

Individual Response: EPA has adopted a flexible, iterative approach to financial assurance in the GS rulemaking. For example, owners or operators may choose from a variety of financial instruments to meet their financial responsibilit y obligations, provided th e Director determines that the operator's proposed fina ncial responsibility demonstrati on is adequate to pay for each activity for which financial res ponsibility must be demonstrate d, including corrective action on wells in the AoR, injection well plugging, PISC and site closure, and emergency and remedial response. The allowable instruments are identifie d at §146.85(a). EPA clarifies that it will allow owners or operators to use separate and or multiple financial responsibility instruments for different GS activities, and that owners or operators can be releas ed from an instrument when the phase of the project for which the instrument was required is complete, as specified in §146.85(b)(1). However, owners or operators must demonstrate adequate fi nancial responsibility

for all activities for which financ ial responsibility is required w ith their permit applications, per §146.85(a). See the final rule and preamble for fu rther discussion of EPA's final approach to financial responsibility.

Given that the practice of GS is fairly ne w and EPA does not have enough information in supporting future prediction, EPA plans, every six years, to collect and review data on GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determ ine if modifications to the requirements are appropriate or necessary.

Letter ID: 0224 Comment ID: 21699 Letter Lines: 680 to 707

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking comment)

Comment Code: 5434 2.9.1.2 Need for additional instruments (seeking comment)

Comment: (1) Allow for a Broad Range of Fi nancial Assurance Mechanisms

We support an approach that takes into account changing market conditions and other factors and allows an operator to utilize a wide range and variety of

financial assurance mechanisms to dem onstrate financial responsibility. This should be coupled with the flexibility to combine multiple types of financial assurance mechanisms to demonstrate compliance. The regulations or guidance

should be flexible and authorize EPA to accept and recognize other types of

33instruments, programs or conditions that provide similar re liable assurance.

While the Proposed Rule does not limit the range of financial assurance mechanisms, EPA indicates that the Agen cy is considering revising various guidance documents related to financial assurance. (73 Fed. Reg. at 43520-21.) EPA refers to several reports issued by the United States General Accountability Office ("GAO"), Office of Inspector Gene ral ("OIG"), and the Environmental Financial Advisory Board ("EFAB"). I d. In 2003, the GAO issued a report reviewing, in part, the financial assurance requirement s for Class I injection wells. See GAO Report to the Honorab le Lynn C. Woolsey, House of Representatives, Deep Injection Wells: EP A Needs to Involve Communities Earlier

and Ensure that Financial Assurance Re quirements are Adequate, GAO-03-761, 17-22 (June 2003). GAO noted that there is uncertain ty about the adequ acy of financial assurance requirements, but did not ma ke any conclusions about specific mechanisms. Similarly, in 2005, OIG issued a report reviewing the financial assurance mechanisms under the RCRA progr am. OIG Evaluation Report, Continued EPA Leadership Will Support State Needs for Information and Guidance on RCRA Financial Assurance, Report No. 2005- P-00026 (Sept. 26, 2005). OIG concluded that despite ongoing concerns , the lack of uniform national data prohibited ready identification of th e problems. Id. at 8.

Individual Response: EPA agrees that it is appropriate to al low a flexible approach for financial responsibility. Under the final GS rule, owners or operators have the flexibility to choose from a variety of financial instruments to meet their financial responsibility obligations. Owners or operators may use one or multiple financial responsibility instruments for well plugging and PISC (§146.85(a)(6)). However EPA will not allo w for a separate financial responsibility demonstration for well plugging and PISC (i.e., a demonstration submitted prior to well plugging and the beginning of the post-injec tion site care period rather than with the permit application). A demonstration of financial responsibility for all ph ases of the GS project will be required prior to

the issuance of a Class VI permit (§146.85(a)(5)(i)).

EPA is developing guidance (a vailable on EPA's website at http://water.epa.gov/type/groundwater /uic/wells_sequestra tion.cfm) to help owners or operators, permitting authorities, and third parties choose and evaluate appr opriate financial methods, and states may set more specific financial respons ibility requirements if they so choose.

Letter ID: 0224 Comment ID: 21700 Letter Lines: 709 to 712

Comment Code: 1910 1.4.4 Stakeholder outreach

Comment: As EPA develops revisions or potential modifications to financial assurance guidance that would be applied to UIC pe rmits, it should provid e further public notice, review and engagement opportunities that allow for feedback to EPA on specific proposals.

Individual Response: EPA will make draft guidance manuals on the GS rule available to the

34public for comment before finalizi ng the rule. In addition, EPA is using an adaptive approach to regulating GS under the UIC Program. Even after finalization of the GS regulation, the Agency plans to collect and review da ta every six years on GS proj ects to determine whether the appropriate amount and types of information a nd appropriate documentation are being collected,

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

Letter ID: 0224 Comment ID: 21701 Letter Lines: 714 to 743

Comment Code: 5436 2.9.1.3 Allowing separate financial demonstrations for plugging and abandonment and post-injection si te care (seeking comment)

Comment: (2) EPA’s Suggestion for a Phased Approach to Financial Assurance for PostInjection Site Care Should be Adopted

EPA is relying on an adaptive management approach for regulation of CO2 injection. (73 Fed. Reg. at 43522.) EPA specifically requested comment on allowing separate financial demonstration to be submitted for well-plugging and for post-injection site care. In the Preamble, EPA states that:

Since post-injection site care has the pot ential to extend many years into the future, subsequent to the time a permit is issued, the Agency believes that it may be advantageous to require the a pproval of the well plugging financial demonstration at permit issuance and the post-injection site care financial demonstration at a later time (e.g., within 180 days of notifying the Director that the well will be plugged and abandone d). Trying to determine the cost for post-injection site care, possibly 30 to 50 years in the future, could be difficult, as could the approval of a financial demonstration.

(73 Fed. Reg. at 43522.) We agree with EPA’ s stated rationale and recommend that EPA specifically incorporate language in the Final Rule that describes the

manner in which determinations and demons trations of financial assurance for post-injection site care will be postponed until a later time as discussed by

EPA.

(3) Clarifying that adaptive management approach allows for phased financial

assurance release In accorda nce with the adaptive management approach for CCS, the rulemaking should clarify that the fina ncial assurance can be released (or amounts reduced) as particular activities are completed and re gulatory criteria are met (e.g., well plugging for correc tive action). Also, the owner or operator should be able to use site-speci fic data gathered from such activities to support revisions to site-specific financial assurance requirements.

Individual Response: In the final rule, owners or operators are required to demonstrate, with their permit application, adequate financial resp onsibility for specific GS activities, including plugging and post-injection site ca re, per §146.85(a). EPA clarifies at §146.85(a)(6) that, prior to obtaining a Class VI permit, an owner or opera tor may demonstrate financial responsibility by

35using one or multiple qualifying financial instruments for specific GS activities, thereby realizing greater flexibility and cost savings from this re gulation. In the event that the owner or operator

combines more than one instrument for a specific GS activity (e.g., well plugging), such

combination must be limited to instruments th at are not based on fi nancial strength or performance (i.e., self insurance or performa nce bond), for example trust funds, surety bonds guaranteeing payment into a trust fund, letters of credit, escrow account, and insurance. In this case, it is the combination of instruments, rath er than the single instru ment, which must provide financial responsibility for an amount at l east equal to the current cost estimate.

EPA recognizes that there are chal lenges associated with estimati ng costs for activities that will occur far in the future. However, the Agency beli eves that owners or operators must demonstrate that financial resources are available to plug the injection well and provid e post-injection care at the time the Class VI well is permitted.

EPA agrees that GS technologies and cost estima ting methods are likely to change and improve as GS is deployed nationwide. However, EPA be lieves that past injec tion practices provide a good foundation for estimating the necessary costs and demonstrating financial responsibility. EPA envisions that financial responsibility updates required at the time of AoR reevaluation or at other frequencies specified by the Director, will provide opportunities to refine the cost estimates and adjust the financial responsib ility instruments as appropriate.

In order to assist owners or operators and financial instituti ons in achieving accurate cost estimates for all GS activities, EPA plans to i ssue financial responsibil ity guidance that will include a discussion of how to estimate costs, incl uding how to adjust cost estimates for inflation to account for the long-term nature of GS pr ojects, in its guidance on meeting financial responsibility requirements for GS wells.

EPA clarifies that the final rule , at §146.85(b)(2), allows releas e from a financial instrument when the phase of the project for which the inst rument was obtained is complete, assuming that all other financial obligat ions have been met.

Letter ID: 0224 Comment ID: 21702 Letter Lines: 745 to 758

Comment Code: 1420 1.2.1.1 Support the GS rulemaking

Comment: CONCLUSION

HEI commends EPA for the tremendous am ount of work that EPA has done in preparing the Preamble and Proposed Rule in an expedited timeframe. After due

consideration of studies and analyses performed by international research organizations, non-governmental organizations, sister-age ncies, and scientists worldwide, EPA’s research has determined that CCS could be "a key mitigation technology for achieving domestic emissions reductions," and CCS has the "potential to play a significant role in climate change mitigation scenarios." (73 Fed. Reg. at 45496.) HEI applauds EPA’ s willingness to play a significant role in this Nation’s strategy to address climate change. We are very supportive

36of EPA’s effort to implement a regulatory scheme that will both protect one of our vital resources, USDWs, and facilitat e the implementation of CCS technology and geologic sequest ration of CO2.

Individual Response: EPA believes that the creation of a new injection well class (VI) under the existing UIC Program is necessary to enable the use of GS as a climate change mitigation technology in a manner that protects USDWs from endangerment. EPA agrees that the UIC Program, under the authority of the SDWA, provides a strong fram ework for regulating injection of CO2 for GS and adds that the GS regulati on tailors the UIC requirements to address the unique issues associated with large-scale GS including large injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the potenti al presence of impurities in captured CO2, and its mobility within subsurface geologic formations.

Letter ID: 0224 Comment ID: 21703 Letter Lines: 760 to 770

Comment Code: 1000 1. General and Administrative Comments

Comment: Significantly, this technology does not st art on a blank slate. The Oil & Gas industry has extensive, relevant experien ce with injection into the subsurface that can inform this rulemaking. Moreove r, BP is a leader in studies and demonstration projects conducted ar ound the world regarding geologic sequestration of CO2. The comments submitted here are in large measure based upon this significant experience and techni cal knowledge. We would be pleased to review our comments and/or any ques tions that EPA may have regarding our

comments at EPA’s convenience. HEI also welcomes the opportunity to provide additional information or input to EPA as EPA continues its evaluation and study of comments, scientific papers/studies or other information submitted or considered in this rulemaking process.

Individual Response: EPA acknowledges the comment. EPA r ecognizes that the oil and gas industry has decades of experience injecting CO 2 for the purpose of EOR. The GS rulemaking builds upon existing experience and knowledge about safe injection practices in EOR and other injection industries, with tailored requirements that address the unique na ture of CO2 injection

for GS.

Please see the remainder of EPA's responses to th is comment for further details. For additional information on EPA's final regulatory approach, pl ease see the final rule and preamble, including the discussion of the repermitting of Class II EOR wells for GS, as well as the rulemaking

docket.

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