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.BP Alternative Energy International Limited, a company registered in England and Wales with the company number 1553681, VAT num ber GB 243 5105 93 and whose registered office is

Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP.

BP Alternative Energy Holdings Limited, a company registered in England and Wales with the company number 2515099, VAT number G B 243 5105 93 and whose registered office is

Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP 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: BP Alternative Energy North Amer ica Inc.’s Comments on United States Environmental Protection Agency’s Proposed Rule: Federal Requirements under the Underground Injection Contro l (UIC) Program for Carbon Dioxide

(CO 2 ) Geologic Sequestration (GS) Wells

Dear Director Dougherty:

BP Alternative Energy North America Inc. (“BP”) is pleased to submit its

comments on the United States Envir onmental Protection Agency’s (“EPA”) Proposed

Rule: Federal Requirements Under the Undergr ound Injection Control (UIC) Program

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). BP 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 participation both before and after publication of the Proposed Rule. Furthermore, it is ev ident from the Proposed Rule that EPA considered and incorporated many of the stakeholders’ comm ents from the public workshops. Accordingly, EPA adopted a frame work that is intended to encourage the CO2 Storage Manager, CCS Technology BP Alternative Energy North America Inc. 

## D. Brian Williams

BP Alternative Energy North America, Inc.

501 Westlake Park Blvd.

MC – 9.188A

P O Box 3092

Houston, Texas 77253-3092

Direct: (281) 366-4833

Main: (281) 366-2000

Mobile: (713) 471-6474

Fax: (281) 366-7416

williadb@bp.comBP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 2 of 20

deployment of carbon capture and sequestration or storage (“CCS”) in a manner that is protective of underground sources of dr inking water (“USDWs”). There is growing consensus among scientists, environmental groups and members of government that CCS will play a critical role in addressing greenhouse gas emissions.

The comments herein are founded on k nowledge and experience gained through decades of industry operations, and are intended to provide constructive input on the Proposed Rule. BP’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 CO 2 . BP concurs with EPA’s conclusion that CCS presents a “key climate change mitigation technology.” (73 Fed. Reg. at 43495.)

In the context of geologic sequestration of CO 2 , it is imperative to maintain flexibility in the regulatory r equirements 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 protective of USDWs. Rather, each site has site-s pecific characteristics that merit differing requirements. Indeed, what m ay appear to be a standard protective 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, BP strongly encourages EPA to provide performance standards for the various phases of a geologic sequestrati on project (i.e., site characterization, operation and site closure), while providing the Director flexibility to add requirements as necessary to address site-specific char acteristics. 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 requirements that address site specific characteristics. Furthermore, it ensures that project costs will be commensurate with the geologic risk, and wi ll further the continued evolution of the best technologies.

Our comments address the following important topics: (A) Enhanced Oil Recovery or Enhanced Gas Recovery (“EOR/EGR”) and CO 2 Storage; (B) Wells, Monitoring & Operations; (C) Site Closure Period; (D) Financial Assurance; and (E)

Issues Related To Oil & Gas Production. BP further joins in the comments submitted by the American Petroleum Institute.BP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 3 of 20

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

BP commends EPA for its recognition, 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 containers that have trapped fluid (both liquid and gaseous) hydrocarbons for millions of years; and (2) oil and gas exploration and production

activities have created a wealth of know ledge and geologic data that can support the 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 operating exper ience. 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 discussion and acknowledgement in its Proposed Rule 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 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 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 anthropogenic CO 2 for EOR/EGR will provide ma ny lasting benefits to the United 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:

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

• Much of the required infrastructure a nd 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 25BP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 4 of 20

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 earlymover CCS projects.

EOR and Storage have the added benefit of increasing domestic energy supplies in the face of increasing dema nd. Carbon dioxide 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 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 In tergovernmental Panel on Climate Change (“IPCC”) has agreed that EOR technology can provide 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 t he technical development and safe deployment of CCS projects in other types of geologic formations. 2

(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 the cost of an EOR/EGR project. Consequently, CO 2 is a valuable commodity to EOR/EGR operators and is treat ed 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 operat ions cease. Any injected CO 2 that returns to the surface during production operations is s eparated from the hydrocarbons and reinjected for additional enhanced recovery use.

Approximately 30% to 50% of the injected CO 2 volume typically remains permanently stored in the oil or gas reserv oir 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

best 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

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.BP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 5 of 20

operations cease (and the field is blown down to recover any CO 2 available for use in another operation), wells are closed a nd the remainder of the injected CO 2 remains permanently stored underground. However, an EOR operator could quite easily, at its option, manage operations to store the injected CO 2 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 CO 2 can be trapped and stored for long term during EOR operations and continues afterwards. Fur thermore, existing Class II regulations and industry practice employ proven methodologie s to conduct these operations 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 sequestra tion (or long term storage) of CO 2 occurs during EOR/EGR operations and continues afte r operations cease – thus EOR and Storage. BP supports EPA’s statement that EOR/E GR, 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 int ent, which we strongly support, that the proven Class II program 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 Pr oposed 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 requirem ents are under Class II; and (b) when CO 2 is exclusively injected for storage, the app licable requirements are under Class VI.

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

BP 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 CO 2 is occurring 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 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 intent of the operat or. As currently drafted, the Proposed Rule m ay be interpreted – contrary to EPA’s intent – to require EOR/EGR operations to proceed under Class V I. API has submitted specific languageBP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 6 of 20

to clarify that the applicable well cl ass 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 multi-stakeholders including environmental groups, various asso ciations and different industries (the “Multi-Stakeholder Discussions Group”); we also support the language recommended in the correspondence from the MSDG da ted 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 wi th EPA’s intent, remain in Class II and are subject to the existing Cl ass II regulations – wh ich have adequately safeguarded USDWs in the context of EOR/EGR operations for decades.

The MSDG has also agreed to continue discussions regarding specific rules that would be applicable to geologic sequestration of CO 2 in oil and gas formations following the completion of EOR/EGR producti on. 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 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 addre ss risks associated specifically with oil and gas formations, rely upon information and data gathered during the terminated EOR/EGR production activities and 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 maximi ze the efficient use of administrative

resources and allow for seamless transiti oning of operations from EOR and geologic sequestration of CO2 to injection of CO2 only for geologic sequestration.

BP requests that EPA consider the for egoing 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 CO 2 Storage

After the EOR and Storage projects conclude produc tion of oil or gas, injection

of CO 2 may continue at the option of the oper ator to utilize fully all available pore space. EPA regulations should fac ilitate this transition from EOR and Storage toBP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 7 of 20

exclusively storage operations when EOR/ EGR operations are completed. EPA’s decision to allow grandfathering of constru ction requirements in sections 146.81 and 146.86 of the Proposed Rule is an exce llent example of both protective and reasonable regulation. BP supports EPA ’s proposal and recommends that EPA expand the grandfathering provisions to enc ourage and facilitate c ontinued 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) regardi ng Operations; and Section 146.89(b) and (c) (continuous monitoring and specific yearly te sts, respectively) regarding Mechanical Integrity. Existing, operati onally-compliant, Class II EOR-wells will continue to protect USDWs, as established by their operational histories, even when injection is for the exclusive purpose of CO 2 sequestration without the foregoing additional Operation or Mechanical Integrity requirem ents. In addition, the follo wing sections of the Proposed Rule simply will not be applicable or pertinent at the time of transition because these provisions presume that no injection has co mmenced. 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 exclusively stor age project because, as a practical matter, performance of certain “baseline measure ments,” “model predictions,” “witnessing of logging and testing,” and “corrective acti ons” will not be possible prior to injection

of CO 2

.

In sum, EPA should expand the gra ndfathering 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, appropria tely expanded grandfathering will facilitate optimal utilization of these proven oil and gas reservoirs for geologic sequestration of

CO 2

.BP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 8 of 20

CCS in connection with EOR provides a forward-looking energy policy for the United States, as it w ill 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 geologic seques tration should provide for effective storage management by requiring the following activities:

• Site characterization that validates t he geological model of the storage site and confirms potential leakage pa thways have been identified and

evaluated;

• Risk assessment that builds upon 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 upda tes predictive performance models.

The appropriate implementation of these ke y areas will ensure the safe and secure operation of a geologic sequestration project.

(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 & oper ating 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 secure manner. Notably, Class II requirements have pr oven to be effective in ensuring the nonendangerment of USDWs. Therefore, BP be lieves it would be prudent to rely upon this extensive existing regulatory and industry experience and knowledge in setting Class VI requirements for wells that inject CO 2 for long term sequestration.

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

BP agrees with EPA that monitoring 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, appropriateBP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 9 of 20

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 year s.” Thus, the key to secure storage is

the appropriate selection and management of the site and these activities should be the focus of any regulatory fr amework for CO2 geo-sequestration. If done properly, a

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

BP has significant and highly relevant experience around monitoring of the subsurface and the surface. For many de cades, BP has been effectively employing a number of monitoring technologies to ensure the safety and integrit y 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 been operating the In Salah, Algeria,

CO 2 storage project where BP (and partner s) has been storing ar ound 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

(such as tracers and conventional 3D seismic) to compare and contrast results as the partnership endeavors to design and develop monitoring technologies and methodologies that are reliable and cost-eff ective, 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 m onitoring program to address those site-specific risks. There are two other monitored, industrial-scale CO 2 injection projects in the world (at Sleipner and We yburn) and the site-specific nature of monitoring requirements is demonstra ted by comparing these three CO 2 storage projects – monitoring that wo rks well at one location may not work at all in another

location.

With respect to monitoring require ments 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 we ll as the early identification of any leakage for appropriate corrective action. BP commends EPA for its efforts in this regard, but believes that further modificat ion is necessary. BP agrees with the proposal to allow a phased approach to conduct corrective action in an Area of Review that has pre-existing well penetrations. Existing wells within the AoR may be idealBP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 10 of 20

candidates for conversion to monitoring or in jection wells during the life of the project and, therefore, should not be plugged and aba ndoned prior to injection. Existing wells within the likely plume area that are not plugged and abandoned should have diagnostic testing to ensure there is minimal risk of vertical leakage prior to conversion to monitoring or injection status.

Furthermore, in various parts of the Proposed Rule, EPA has prescribed particular monitoring technologies. Manda ting any specific technology(ies) would have the adverse effect of (1) promoting pa rticular 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 deploy ment of CCS at commercial scale. Moreover, it would discourage the developm ent of other technologies. BP therefore strongly discourages EPA from promulgating regulations that mandate the use of any specific monitoring technology.

(3) Specific Comments

In addition to the foregoing, BP respec tfully 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 materi als, 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.

BP strongly discourages EPA from setting a requirement to use degradationresistant materials & cement. Actual field observations based upon sampling of in situ casing and annular cements do not suppo rt this general requirement. The studies referenced by EPA in its Preamble expos ed cement in a laboratory setting to a continuously-refreshed supply of CO 2 -saturated brine, whic h then reportedly caused the cement to degrade. (Duguid et al., 2004 and Kutchko et al., 2007.) These studies represent variations in cement alterati on rates due to curing and exposure conditions, but neither supports the requirement for t he use of degradation-resistant materials and cement because the laboratory proc edures that were used do not necessarily represent the actual barrier exposure c onditions in an appropriately cemented operating well. Indeed, the findings of Kut chko’s laboratory study suggested thereBP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 11 of 20

would be limited degradation even after deca des, 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 CO 2 Capture Project, 2008). Both of these field studies identified that hydraulic isolation was maintained acro ss 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 th e type of cement, that is key to delivery of effective isolation and hence prevention of casing corrosion. Furthermore, cement placement to completely fill the annular space between borehole and casing is the primary means of achieving this objective.

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

BP strongly supports, with one modifi cation discussed below, EPA’s actual language of the Proposed Rule in section 146.86(b)(5), which establishes a reliable performance standard that will achieve protection of USDWs. Section 146.86(b)(5)

states, “ Cement and cement additives must be compatible with the carbon dioxide

stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life the geologic sequestration project.“ BP recommends that EPA’s

discussion in the Preamble should be cons istent with the actual language of the Proposed Rule to ensure clarity and remove any ambiguity regarding the performancebased approach set forth in the Proposed Rule.

Furthermore, section 146.86(b)(5) shoul d be amended to base the choice of casing and cement materials on the planned operating life of t he well as opposed to the ultimate duration of the geologic seque stration project. EPA may have set the duration as the life of the project in an effo rt to prevent corrosi on of the casing over the long term after injection has ceased. However, this legitimate concern is mitigated by appropriate plugging of the stat ic well at the end of its life. This plugging could employ corrosion-resistant material, if an extra level of mitigation were deemed necessary at that time based upon site charac teristics. API has submitted specific language to address the foregoing. We support API’s proposed language modification

to section 144.86 (b)(5).BP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 12 of 20

(ii) Horizontal Wells Should Be Approved for Geologic Sequestration

BP agrees with EPA’s discussion regarding the usefulness and benefits of constructing horizontal wells in geologic seques tration projects. It is evident that EPA has done a good amount of research in this ar ea and is well informed on this topic. BP has direct experience with horizontal wells used in connection with geologic sequestration. At In Salah, 1mmtpa CO2 is being sequestered in a formation that is 6,000ft deep, 60ft thick and has permeability of only 10mD. These characteristics are very similar to many deep saline formations in the United States. To do this, requires only three wells, but the wells have very long horizontal sections in the storage formation. In fact, each well is about as l ong as it is deep. Horizontal wells provide a means of achieving high performance completi ons that optimize/improve injectivity. Additionally, horizontal wells can reduce t he risk of leakage because their use limits the number of penetrations through the caprock. There are other options to optimize injectivity as well that include, but s hould not be limited to, hydraulic fracture treatments, multiple injection points al ong 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 zo ne and must be cemented . . . .” (73 Fed. Reg. at 43538; § 146.86(b)(3).) This requirem ent is excessive and its implementation would unnecessarily constrain the abilit y to undertake future potential well interventions that support downhole monitori ng and well remediation, if such become

necessary.

To avoid such an unintended result, BP recommends that EPA not mandate the placement of an isolation casing string fro m the surface, but rather allow the casing string to extend from beneath the surf ace or otherwise based upon site

characteristics. Cement should cover t he uppermost caprock (within the Area of Review) by approximately 500 feet; cement coverage should not be required all the way to surface. The ultimate decision for e ach project should rest with the Director since each storage site is unique in the geol ogical intervals of t he caprock(s), injection zone(s) and position relative to USDW(s). Moreover, any expectation to cement in the injection interval should permit the use of external casing packers or other isolation methods in conjunction with cementi ng requirements across the caprock, as

discussed above.BP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 13 of 20

(iv) Definition of Carbon Dioxide Stream

Section 146.81 of the Proposed Rule 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 improv e the injection process. This subpart does not apply to any carbon dioxide stre am that meets t he definition of a hazardous waste under 40 CFR part 261.

By limiting the definition to “emission sources,” the Class VI regulations may have the unintended effect of narrowing 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 protecting 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 plant)” from the definition contained in section 146.81 of the Proposed 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 Lower-Most USDW

The Proposed Rule restricts injection of CO 2 to below the lower-most 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.

BP 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 ju stified by technical knowledge or historical industry experience. For example, Class II requirements have proven successful in protecting USDWs even though injection into certain reservoirs has occurred above

the lower-most USDW. Given the EPA’s effort in adopting a general performancebased approach, injection should be allow ed to proceed into acceptable reservoirs provided the reservoir is demonstrated to provide secure CO 2 storage above and below the injection formation.

A containment system with appropriate site characterization, risk assessment and monitoring is the key to secure stora ge and protection of US DWs. Proximity of the injection zone to USDWs (i.e. whether shallower or deeper) is not the appropriate criteria for protection of USDWs because pr oximity alone does not materially impactBP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 14 of 20

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, BP al so disagrees with the requirement in

section 146.86(b)(2) that “(s)urface casi ng must extend through the base of the

lowermost USDW and be cemented to the surf ace.” One reason is that at certain potential storage sites USDWs may be lo cated at depth; consequently, it would be technologically infeasible to construct su rface casing to the requisite depth prescribed by the Proposed Rule.

In summary, EPA should not mandate a re quirement of inject ion only below the lower-most USDW nor a minimum depth for injection of CO 2 . Such a comprehensive prohibition would unjustifiably exclude poten tial storage sites that do not pose an endangerment to USDWs.

(vi) Injection Well Operation & Mech anical Integrity Requirements

Consistent with the earlier discussion a bout blanket construction limitations, BP also disagrees with universal mandates regarding certain CO 2 injection operations. EPA should not include automatic downhole shut-in devices as a standard requirement

for CO 2 injection wells (section 146.88(e)). An across-the-board requirement for

installation of downhole devices is exce ssive – unsupported by technical knowledge and industry experience – and would impos e unnecessary costs. Overpressure protection is best achieved by ensuring co mpatibility of the casing/tubing material design strength with the surface injectio n (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 stor age sites. Rather, the requirement of

downhole shut-in devices should be left to the discretion of the Director.

With regard to validating mechanical integrity of CO2 injection wells, BP generally agrees with EPA’s suggestion to e valuate the “absence of significant leaks” by monitoring at some regular frequency the injection pressure, flow rate, injected volumes 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 case s. Where periodic pressure testing is implemented, the pressure should be cons idered by evaluation of the formation potential instead of casing bur st or tubing collapse limit.

The frequency of the monitoring should be defined not as “continuous” but as “regular” or “periodic” based upon site ch aracteristics because regular monitoring (e.g., every minute or hour) will often be adequa te. For example, fluid volume in theBP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 15 of 20

annulus is static and requires evaluation of a pressure pulse to determine the depth of top of fluid. Therefore, this should be m onitored on a monthly or quarterly basis to support the pressure data.

Section 146.89(c) lists specific methodolog ies to monitor fluid movement. BP 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 Preamble th at 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 EPA also concluded that “ the actual time for CO2 plume stabiliziation . . . will be very site-specific , being influenced by geologic factors such as formation perme ability, geochemistry, and the degree of capillary trapping.” (Id .) However, the Proposed Rule establishes a default 50-year period (following the cessation of injecti on) during which the operator must conduct monitoring to demonstrate that “the carbon di oxide plume and pressure front have stabilized and the geologic sequestration pr oject does not pose an endangerment to

USDWs.” (See § 146.93(b).) The designation of a 50- year time-period without regard to particular site characteristics is arbi trary and not supported by existing scientific studies or industry experience. Moreove r, 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 deterr ent to commercial investment in geologic sequestration projects.

BP urges EPA to adopt the performance standard that EPA considered in its review. EPA considered three options: (1) fi xed period; (2) performance standard; and (3) combination of fixed period and performan ce 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 practical 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 requirement for Class I hazardous wells, which provides that the timeframe for post-injection site care ends when the pl ume 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-injecti on 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-BP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 16 of 20

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 performan ce. 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 sites that are less well confined (e.g., deep sali ne formation without a conventional 4-way closure), the CO 2 could move around for some time even after injection ceases before stabilizing, and might therefore require a lo nger period to allow for additional residual and solubility trapping.

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

determine the timeframe for site closure. We also suppo rt 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 Propo sal as opposed to a fixed period is it establishes clear criteria that an oper ator must demonstrate before obtaining site closure based upon particular site charact eristics and is, ther efore, reasonable applicable to any storage site as opposed to a standard based upon a fixed-duration. The current proposal of 50-years minimum, ev en subject to potential reduction, would result in significantly discouraging the deploy ment 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 esta blish financial responsibility (or “financial assurance”) to cover the costs of plugging 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 facilitating 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.

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

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

assurance mechanisms to demonstrate financ ial responsibility. This should be coupledBP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 17 of 20

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 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 related to financial assurance. (7 3 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 t he Environmental Financial Advisory Board

(“EFAB”). Id. In 2003, the GAO issued a report re viewing, 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 th at Financial Assurance Requirements are Adequate , GAO-03-761, 17-22 (June 2003). GAO noted that there is uncertainty about the adequacy of financial assurance requirem ents, but did not make any conclusions about specific mechanisms. Similarly, in 2005, OIG issued a report reviewing the

financial assurance mechanisms under t he 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 despite ongoing concerns, the lack of uniform national data prohibited ready 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 engagement opportunities that allow for feedback to EPA on specific proposals.

(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 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 postinjection 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 appr oval 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 abandoned). Trying to determine the cost for post-BP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 18 of 20

injection site care, possibly 30 to 50 ye ars 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 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 fina ncial assurance can be released (or amounts reduced) as particular activities are complet ed and regulatory criteria are met (e.g., well plugging for corrective action). Also, t he owner or operator should be able to use site-specific data gathered from such activit ies to support revisions to site-specific financial assurance requirements.

(E) ISSUES SPECIFICALLY RELATE D TO OIL & GAS PRODUCTION

EPA has appropriately restricted the applicability of Class VI regulations to projects that are exclusively geologic sequestration projects. Furthermore, BP appreciates EPA’s efforts to limit this ru lemaking to the authority vested in EPA by Congress pursuant to the Safe Drinking Wat er Act (“SDWA”). BP requests that EPA

include some of the discussion in the Prea mble to the Final Rule to ensure that

unrelated activities in the Oil & Gas industry are not impacted by unintended inferences or interpretations of the Proposed Rule.

(1) Property Rights Issues Are Matter of State Law

EPA accurately states that the SDWA does not afford EPA the authority to regulate many issues involved in CO 2 sequestration, including property rights which are regulated under state law. (73 Fed. Reg. at 43495.) In many instances, the owner of the surface property rights may be differ ent than the owner of the subsurface mineral rights. There may be a legal question as to who owns the subsurface storage rights as between, for example, the surface property rights owner and the mineral rights owner. This is a matter of state law as correctly discussed by EPA. BP requests that EPA expand on its assertion in the Preamble that it does not have authority to regulate in this area and that nothing in the Proposed Rule should be interpreted or inferred as a grant of subsurface storage rights.BP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 19 of 20

(2) Organic-Rich Shales Are Primary Remaining Supply of Natural Gas

EPA also states in the Preamble that or ganic-rich shales are potential reservoirs for geologic sequestration of CO 2 . However, these shales are also the single largest source of natural gas remaining in the Un ited States, and will likewise help to ensure that low-carbon energy supplies are available to fuel the United States’s economy.

EPA should include in its Preamble a clear statement that nothing in the Preamble and/or the Proposed Rule should be interpre ted or inferred as a preference for the use of these organic-rich shales for geolog ic sequestration as opposed to natural gas production. Whether organic-rich shales are used for natural gas production or geologic sequestration should be a matter left to negotiations between private parties.

(3) Proposed Rule Should Not A ffect Injection of Oil & Gas Waste

Oil and gas waste (such as produced water and amine waste gases [CO 2 and

H 2 S]) are often injected back into the reservoir after separation during oil and gas production activities. This type of injecti on is and has been historically permissible under Class II regulations. (See 40 CFR § 144.6(b)(1).) EPA was silent on whether the Proposed Rule would in any manner affect the applicability of the Class II well regulations for injection of oil and gas wast e. EPA should indicate in its Preamble to

the Final Rule that the Final Rule does not alter in any manner the applicability of Class II regulations to injecti on of oil and gas waste.

CONCLUSION

BP 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 organiza tions, sister-agencies, and scientists

worldwide, EPA’s research has determi ned 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.) BP applauds EPA’s willingness to pl ay a significant role in this Nation’s strategy to address climate change. We are very supportive of EPA’s effort to implement a regulatory scheme that will bot h protect one of our vital resources, USDWs, and facilitate the implementat ion 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, relevant 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 r egarding geologic sequestration of CO 2 . TheBP’s Comments To EPA’s Proposed Rule

Docket ID No.: EPA-HQ-OW-2998-0390 Page 20 of 20

comments submitted here are in lar ge measure based upon BP’s significant experience and technical knowledge. We would be pleased to review our comments and/or any questions that EPA may h ave regarding our comments at EPA’s convenience. BP also welcomes the opportuni ty to provide additional information or input to EPA as EPA continues its evalua tion and study of comments, scientific papers/studies or other information subm itted or considered in this rulemaking

process.

Please contact the undersigned with any questions or comments.

BP Alternative Energy North America Inc.



## Brian Williams by Asteghik Khajetoorians

____________________________________ Brian Williams CO2 Storage ManagerLetter ID: 0225

Commenter: Brian Williams Organization: BP Alternative Ener gy North America, Inc. (BP)

Letter ID: 0225 Comment ID: 21711 Letter Lines: 57 to 61

Comment Code: 1910 1.4.4 Stakeholder outreach

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

Individual Response: EPA acknowledges the comment and agrees that input of and participation by a wide spectrum of stakeholders is a vital component of successful rulemaking. The Agency appreciates the degr ee 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: 0225 Comment ID: 21712 Letter Lines: 61 to 74

Comment Code: 1330 1.1.3.1 Support use of GS in general

Comment: 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.

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. BP’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. BP 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.

1Letter ID: 0225 Comment ID: 21713 Letter Lines: 76 to 95

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

Comment: 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 technology is continually advancing. For geologic sequestration of CO2, "one-size-fits-all" is not an approach that is necessarily or reasonably protective of USDWs. Ra ther, each site has site-specific characteristics that merit differing requireme nts. Indeed, what may appear to be a standard protective measure in the contex t of a particular s ite could actually have the opposite effect and increase pot ential risks at another site. (See A Technical Basis for Carbon Dioxide Storag e, CO2 Capture Project, December 2008.)

Consequently, BP strongly encourages EPA 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 en sures that project costs will be commensurate with the geologic risk, and w ill 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: 0225 Comment ID: 21714 Letter Lines: 103 to 257 ; 847 to 852

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)

2Comment: (A) Importance of EPA’s Recognition That EOR/EGR and Storage of CO2 Occur At

the

Same Time

BP commends EPA for its recognition, as stated 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 o pportunity to kick-start large-scale geologic sequestration of CO2, buildi ng on 100 years of oil and gas field operating experience. Consequently, many o il and gas reservoirs are available now to serve CCS projects at a commerc ial 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:

- 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);

3- 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 reinjected for add itional 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 of 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.

4(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. BP 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

BP requests that EPA amend s ections 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 geologic sequestration of CO2. In addition to the reasons stated above, th is clarity is needed because some amount of CO2 is sequestered or stored during EOR/EGR operat ions regardless of the intent of the operator. As curre ntly drafted, the Proposed Rule may be interpreted - contrary to EPA’s inte nt - to require EOR/EGR operations to proceed under Class VI. API has submitted specific language BP’s Comments To EPA’s Proposed Rule to clarify that the applicable well class is Class II. We support API’s proposed language modi fications 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 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.

5The 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.

[FN1] Currently, over 2 billion cubic feet of naturally-occurring CO2 is used daily for EOR operations and the volume is growing.

[FN2] Notably, it is estimated that site characterization of saline reservoirs will likely cost tens of millions of do llars 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.

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

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

6EPA 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: 0225 Comment ID: 21715 Letter Lines: 259 to 316

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

Comment: BP 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 c onclude production of oil or gas, injection of CO2 may continue at th e option of the opera tor to utilize fully all available pore space. EPA re gulations should facilitate this transition from EOR and Storage to BP’s Comments To EPA’s Proposed Rule exclusively storage operations when EO R/EGR operations are completed. EPA’s decision to allow grandfathering of c onstruction requirements in sections 146.81 and 146.86 of the Proposed Rule is an excellent example of both protective and reasonable regulation. BP supports EPA’s proposal and recommends that EPA expand the grandf athering provisions to encourage and facilitate continued injec tion of CO2 exclusively for storage when EOR/EGR operations cease.

Specifically, 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 Inte grity. Existing, opera tionally-compliant,

Class II EOR-wells will con tinue to protect USDWs, as established by their

7operational histories, even when injecti on is for the exclusive purpose of CO2 sequestration without the fo regoing additional Operation or Mechanical Integrity requirements. In addition, the following se ctions of the Proposed Rule simply will not be applicable or pertinent at the time of transition because these provisions presume that no injection ha s 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).

EPA 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

8discussion 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. This rule focuses on ensu ring that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.

Letter ID: 0225 Comment ID: 21716 Letter Lines: 318 to 324 ; 326 to 328

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 time and confir ms 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: 0225 Comment ID: 21717 Letter Lines: 330 to 334

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.

Individual 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.

9Letter ID: 0225 Comment ID: 21718 Letter Lines: 336 to 348

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, BP 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. EPA believes that GS is suffi ciently different from Class II ER operations to warrant the tailored construction requirements for Class VI wells at §146.86. For example, the volume of CO2 anticipat ed to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will be different, with Class VI injection operations involving large volumes of CO2 and likely havi ng higher pressures within their storage formations than Class II ER pr ojects. Therefore, Class VI GS reservoir pressures will increase more in comparison to Class II ER during the injection phase of the GS project.

The final GS rule, at §146.81(c), allows the 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 Directors 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.

10Regarding operational requirements, EPA believe s such requirements for Class VI wells are necessary to protect USDWs from endangerment by providing multiple safeguards to ensure that well integrity, containment of flui ds within the injection zone, and that the integrity of the confining zone is not compromi sed. Some of the operating requirements in the GS regulation (e.g., pressure limitations or annulus pressure re quirements) 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: 0225 Comment ID: 21719 Letter Lines: 350 to 364

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

BP 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.

EPA is developing guidance on testing and mon itoring to assist owne rs or operators and Directors in evaluating requi rements under §146.90, including pr oposed monitoring plans. The guidance describes available technologies a nd recommended approaches for implementing a testing and monitoring plan, including pre-ope rational geophysical l ogging and testing of injection wells, MITs, injecti on well testing during operation, groundwater quality monitoring, tracking the CO2 plume and pressure front, a nd soil gas and surface air monitoring which may

11be 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: 0225 Comment ID: 21720 Letter Lines: 366 to 389

Comment Code: 1840 1.4.1.3 Other research

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

Comment: BP has significant and highly relevant experience around monitoring of the subsurface and the surface. For many decad es, BP has been effectively employing a number of monitoring technol ogies to ensure the safety and integrity of its customary oil and gas operations, includi ng CO2 EOR-related operations since the

1970’s in West Texas and Alaska. Notabl y, since 2004 BP has been operating the In Salah, Algeria, CO2 storage project wh ere 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 St orage project also incorporates a research project to test CO 2 storage monitoring technologi es with a program that is much more extensive than would be appr opriate for a commercial project. At In Salah, BP is testing new technologies (s uch as satellite imagery and microseismic) and conventional oilfield technologies (such as tracers and conventional 3D seismic) to compare and contrast results as the partnership endeavors to design and develop monitori ng technologies and me thodologies that are reliable and cost-effective, given the expectation of future 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 track 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

12Water." 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, 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.

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, includi ng 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: 0225 Comment ID: 21721 Letter Lines: 391 to 397

Comment 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

13stabilization of the CO2 plume in th e subsurface as well as the early identification of any leakage for appropr iate corrective action. BP commends EPA for its efforts in this regard, but believes that further modification is necessary. BP 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 operator 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.

Letter ID: 0225 Comment ID: 21722 Letter Lines: 397 to 398

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

Comment: necessary. BP 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

14and 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: 0225 Comment ID: 21728 Letter Lines: 399 to 404

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: 0225 Comment ID: 21729 Letter Lines: 406 to 414

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

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. Manda ting any specific tec hnology(ies) would have the adverse effect of (1) promoting particular tec hnologies 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 technologies. BP 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

15developing 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: 0225 Comment ID: 21730 Letter Lines: 416 to 461

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

Comment: (3) Specific Comments

In addition to the foregoing, BP respect fully submits the following areas of specific comment:

(i) Well Design and Construc tion To Avoid Corrosion

One area of comment requested by EP A relates to requirements for "degradation-resistant well construction ma terials, such as acid- resistant cements and corrosion resistant casing." (73 Fed. Reg. at 43510) Based upon historical industry experience and fi eld studies, this would be an excessive requirement and not reasonably necessary to prot ect USDWs. Risk Profile of a CO2 Geological Storage Project: Wells, by Christopher, Crow, Dodds, Wright, Williams, March 2008.

BP strongly discourages EPA from setting a requiremen t 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 degradation-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.

16EPA’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: 0225 Comment ID: 21731 Letter Lines: 463 to 472

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

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

Comment: BP 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

17quantity to maintain integrity over the design life the geologic sequestration project." BP recommends that EPA’s discussion in the Preamble should be consistent with the actual language of the Proposed Rule to ensure clarity and remove any ambiguity regarding the 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: 0225 Comment ID: 21732 Letter Lines: 474 to 483

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 level 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

18wells. 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: 0225 Comment ID: 21733 Letter Lines: 485 to 499

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

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

BP agrees with EPA’s discussion regard ing the usefulness and benefits of constructing horizontal wells in geol ogic sequestration projects. It is evident that EPA has done a good amount of research in this area and is well informed on this topic. BP has direct experience with horizontal wells used in connection with geologic sequestration. At In Salah, 1mmtpa CO2 is being sequestered in a formation that is 6,000f t deep, 60ft thick and has permeability of only 10mD. These characteristics are very similar to many deep saline

formations in the United States. To do this, requires only three wells, but the wells have very long horizontal sections in the storage formation. In fact, each well is about as long as it is deep. Horizontal wells provide a means of achieving high performance completions that optimize/improve injectivity. Additionally, horizontal wells can reduce the risk of l eakage because their use limits the number of penetrations thr ough the caprock. There are other options

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.

Letter ID: 0225 Comment ID: 21735 Letter Lines: 499 to 502

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)

19Comment: limits the number of penetrations thr ough the caprock. There are other options to optimize injectivity as well that in clude, but should not be limited to, hydraulic fracture treatments, multiple in jection 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 of Class VI wells, includin g 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: 0225 Comment ID: 21736 Letter Lines: 504 to 523

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.

To avoid such an unintended result, BP 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

20Director 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, operation and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity 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 additi onal 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/gr oundwater/uic/wells_se questration.cfm.

Letter ID: 0225 Comment ID: 21737 Letter Lines: 525 to 543

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. Furthermore, the Final Rule shoul d not address the source because it is beyond th e scope of this regulati on. We recommend deleting the phrase "has been 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 inadvertently prec lude other non-emissi on sources of CO2.

Individual Response: EPA disagrees with the suggested edit. The final definition of carbon dioxide stream at §146.81(d) remains unchanged a nd reads as: “[C]arbon di oxide that has been captured from an emission source (e.g., a power plan t), plus incidental as sociated substances

derived from the source materi als and the capture process, a nd any substances added to the stream to enable or improve th e injection process. This subpa rt does not apply to any carbon

21dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261.”

EPA clarifies that the Class VI GS requirements apply to owners or operators of injection wells that will be used to inject CO2 into the subsurfa ce for the purposes of GS. The capture of CO2 is outside the scope of the final rule.

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: 0225 Comment ID: 21738 Letter Lines: 545 to 560

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 lower-most 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.

BP disagrees with such a blanket restric tion, 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.

EPA 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

22between 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: 0225 Comment ID: 21739 Letter Lines: 562 to 569

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 constraints placed on injection should be site-specific, consistent with the containment and cap acity 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 and preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0225 Comment ID: 21740 Letter Lines: 571 to 576

23Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment)

Comment: Related to the depth of in jection, BP also disagrees with the requirement in section 146.86(b)(2) that "(s)urface casing must extend through the base of the

lowermost USDW and be cemented to the 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: 0225 Comment ID: 21741 Letter Lines: 578 to 581

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 an endangerment to USDWs.

Individual Response: As described above, EPA agrees that it is not appropriate to set aminimum injection depth for GS projects and the Agency believes that a determination of sitesuitability for GS (i.e., that subsurface formati ons will receive and confine injected CO2) should be made on a site-specific basis. EPA also ac knowledges that there are limited circumstances

24where injection above the lowermost USDW can be performed in a manner that protects USDWs, as long as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which owners or operators can se ek a waiver of the Class VI injection depth requirements for injection into non-USDW fo rmations above and/or between USDWs.

Letter ID: 0225 Comment ID: 21742 Letter Lines: 583 to 596

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

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

discretion to mandate automatic down-hole shut -off devices in onshore situations that may warrant their use. 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.

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

25a concern, EPA believes that technology has advanced sufficiently to make valve failure a rare occurrence and to appropriately hand le such failure if it occurs. Fo r example, wireline retrievable devices can allow repair or replacement of da maged devices without necessitating pulling the tubing.

EPA believes that requiring the in stallation of automatic surfa ce 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: 0225 Comment ID: 21743 Letter Lines: 598 to 606

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, BP 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 mechanical 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.

26Letter ID: 0225 Comment ID: 21744 Letter Lines: 608 to 613

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 semi-annual basis.

EPA 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 fluid volume as specified at §146.88(e) is a necessary component of monitori ng well mechanical integrity, but believes that knowing the

annulus fluid volume added is sufficient to meet th e intent of the requirem ent. The final GS rule requires that owners or operator s use continuous recording devices to monitor injection pressure, rate and volume; as well as the pressure on the annulus between the tubing and the long string casing. It also modifies the re quirement in the proposed rule to continuously monitor annulus fluid volume; it now requir es recording of annulus fl uid volume added. See §§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

27regulations 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: 0225 Comment ID: 21745 Letter Lines: 615 to 618

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. BP 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).

In 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: 0225 Comment ID: 21746 Letter Lines: 620 to 637

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

28site-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 50-y 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 regul ation, 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 timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. For this reason, the GS rule o ffers owners or operators flexibility regarding

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

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

comments.

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

29substantial 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: 0225 Comment ID: 21753 Letter Lines: 639 to 649

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: BP 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.

EPA believes that the best way to address a ll possibilities, while en suring USDW protection from endangerment, is to set a 50 year default post-injection site care timeframe, with flexibility to: (1) allow the Director discre tion 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

Director discretion to allow a Class VI well owner or operator to demonstrate, based on substantial data during the permitting process, that an alternative PISC timeframe may be appropriate if it ensures non-e ndangerment of USDWs pursuan t 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.

30Letter ID: 0225 Comment ID: 21754 Letter Lines: 651 to 678

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 not pose an endangerment to USDWs. (See e.g., 73 Fed. Reg. 43520.) A performancebased approach is consistent with technical knowledge and historic industry experience. The s ite closure period would be appropriately based on particular site characteris tics and historic site performance. For example, a well-selected and managed sequestration si te (such as an existing oil or gas field) that has met its performance object ives (including plum e stabilization)

will be much more secure and could be cl osed reasonably quickly (potentially, in as few as 2-3 years). At other sites th at are less well confined (e.g., deep

saline formation without a conventional 4-way closure) , 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, BP 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 a 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

31care 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: 0225 Comment ID: 21755 Letter Lines: 680 to 693

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 assurance") 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: Owners or operators may choose from a variety of financial instruments to meet their financial responsibility obligati ons, provided the Director determines that the operator's proposed financial responsibility dem onstration is adequate to protect USDWs from endangerment, which includes the ability to pay for each activity for which financial responsibility must be demonstrated, including corrective action on wells in the AoR, injection well plugging, PISC and site cl osure, and emergency and reme dial response. The allowable instruments are identified at §146.85(a). EPA clarif ies that it will allow ow ners or operators to use separate and multiple financial responsibility in struments for different GS activities, and that owners or operators can be released from an in strument when the phase of the project for which

32the instrument was required is complete, as sp ecified in §146.85(b)(1). However, owners or operators must demonstrate adequate financial re sponsibility for all activities for which financial responsibility is requir ed with their permit applications, per §146.85(a). See the final rule and preamble for further discussion of EPA's fi nal 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: 0225 Comment ID: 21756 Letter Lines: 695 to 722

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 instruments, 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.

33Individual 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 flexib ility 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: 0225 Comment ID: 21757 Letter Lines: 724 to 727

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 subjected the financial responsibili ty guidance to expert review; the final guidance reflects this input. In addition, EP A 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 data every six years on GS projects to dete rmine whether the appropriate amount and types of information and appropria te documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary. EPA will also evaluate whether any changes to the GS rule necessitate revisions to the guidance.

Letter ID: 0225 Comment ID: 21758 Letter Lines: 729 to 760

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:

34Since 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 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 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 accordance with the adaptive management approach for CCS, the rulemaking should clarify that the financial assuran ce can be released (or amounts reduced) as particular activities are completed and regulatory criteria are met (e.g., well plugging for corrective ac tion). Also, the owner or operator should be able to use site-specific data ga thered from such activities to support revisions to site-specific financial assurance requirements.

Individual Response: EPA will allow owners or operators to use separate financial responsibility instruments for well plugging and site closure. Howeve r, owners or operators must demonstrate adequate financial responsibility for all required activities with their permit applications, per §146.82(a)(14), and financial respons ibility will need to be reevaluated prior to well plugging or site closure, or at any othe r time deemed appropriate by the Director. EPA believes this is necessary to ensure that resour ces are available to prevent the endangerment of USDWs in the event that the owner or operator experiences financial difficulties at any time during the life of the GS project.

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.

35In order to assist owners or operators and financial institutions 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: 0225 Comment ID: 21759 Letter Lines: 762 to 770

Comment Code: 1230 1.1.1.2 General comments on the regulatory text

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: (E) ISSUES SPECIFICALLY RELATED TO OIL & GAS PRODUCTION

EPA has appropriately restricted the app licability of Class VI regulations to projects that are exclusivel y geologic sequestration pr ojects. Furthermore, BP appreciates EPA’s efforts to limit this rulemaking to the authority vested in EPA by Congress pursuant to the Safe Dri nking Water Act ("SDWA"). BP requests

that EPA include some of the discussion in the Preamble to the Final Rule to

ensure that unrelated acti vities in the Oil & Gas i ndustry are not impacted by unintended inferences or interpre tations of the Proposed Rule.

Individual Response: EPA clarifies that the final Class VI regulations require that any owner or operator injecting CO2 for the pr imary purpose of long term storage obtain a Class VI permit with some special consideration for the fact that they are transitioning from a well not originally designed to meet Class VI require ments. The Director has the authority to determine at what point a Class VI permit is required for those pr ojects that are transitioning from the primary purpose of EOR to long term storage of CO2. Th e final regulation provides a set of technical

factors for the Director to evaluate in maki ng this determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs when there is an increased risk to USDWs as compared to traditional Class II operat ions while allowing for site-specific flexibility. For more information, please see the discussion on transition of Class II we lls in the preamble to

the final GS rule.

EPA recognizes that the oil and gas industry has decades of e xperience injecting CO2 for the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. EPA also believes that the nature and risks of CO2 injection for the primary purpose of long term storage poses different risks than injection for the prim ary purpose of ER, and therefore has developed new Class VI regulations to address these unique risks. For example, the volume of CO2 anticipated to be injected for long term storag e is significantly greater than for ER operations. Reservoir pressure conditions will also be differ ent, with Class VI injection

36operations involving large volumes of CO2 and likely having higher pressures within their storage formations than Class II ER projects.

Letter ID: 0225 Comment ID: 21760 Letter Lines: 772 to 784

Comment Code: 1310 1.1.2.4 Comments on other "out of scope" issues, e.g., pore space ownership

Comment: (1) Property Rights Issues Ar e Matter of State Law

EPA accurately states that the SDWA doe s not afford EPA the authority to regulate many issues involved in CO2 se questration, includi ng property rights which are regulated under state law. ( 73 Fed. Reg. at 43495.) In many instances, the owner of the surface property rights ma y be different than the owner of the subsurface mineral rights. There may be a legal question as to who owns the subsurface storage rights as between, fo r example, the surface property rights owner and the mineral rights owner. This is a matter of state law as correctly discussed by EPA. BP requests that EPA expand on its assertion in the Preamble that it does not have authority to regulate in this area and that nothing in the Proposed Rule should be interpreted or infe rred as a grant of subsurface storage rights.

Individual Response: EPA clarifies that pore space ownership and surface and subsurface property and mineral rights are ou tside of the scope of the Class VI GS rulemaking. These issues are under the purview of states a nd any of these issues, as they relate to GS, will need to be addressed though stat e regulations.

The UIC program’s authority under SDWA is fo cused on ensuring that where GS technologies are deployed, GS is performed in a manner th at protects USDWs from endangerment.

Letter ID: 0225 Comment ID: 21761 Letter Lines: 786 to 797

Comment Code: 4440 2.4.4.3.4 Injection into organic-rich shales above USDWs (seeking comment)

Comment: (2) Organic-Rich Shales Are Primar y Remaining Supply of Natural Gas

EPA also states in the Preamble that organic-rich shales are potential reservoirs for geologic seque stration of CO2. However, th ese shales are also the single largest source of natu ral gas remaining in the United States, and will likewise help to ensure that low-carbon energy supplies are available to fuel the United States’s economy. EPA should include in its Preamble a clear statement that nothing in the Preamble and/or the Proposed Rule should be interpreted or inferred as a preference fo r the use of these organic-rich shales for geologic sequestration as opposed to natural gas production. Whether

37organic-rich shales are used for natural gas production or geologic sequestration should be a matter left to negotiations between private parties.

Individual Response: EPA clarifies that the GS rule does not address the use of any formation types or specific formations for a particular activity (e.g., GS or natural gas production). Rather, the intent of the GS rule is to ensure that, wher e GS is deployed, it is co nducted in a manner that protects USDWs from endangerment.

Letter ID: 0225 Comment ID: 21762 Letter Lines: 799 to 809

Comment Code: 1310 1.1.2.4 Comments on other "out of scope" issues, e.g., pore space ownership

Comment: (3) Proposed Rule Should Not Affect Injection of Oil & Gas Waste

Oil and gas waste (such as produced water and amine waste gases [CO2 and H2S]) are often injected back in to the reservoir after sepa ration during oil and gas production activities. This type of injec tion is and has been historically permissible under Class II regulations . (See 40 CFR § 144.6(b)(1).) EPA was silent on whether the Proposed Rule would in any manner affect the applicability of the Class II well regulati ons for injection of oil a nd gas waste. EPA should

indicate in its Preamble to the Final Rule that the Final Rule does not alter in any manner the applicability of Class II re gulations to injecti on of oil and gas

waste.

Individual Response: The Agency clarifies that the final Class VI GS rule does not require owners or operators to use GS technologies, no r does it impact business as usual for Class II owners or operators that are inje cting CO2 to enhance production of oil or gas. Those owners or operators that choose to transition from enhanced recovery to GS may do so, provided they meet the requirements for Class VI wells.

Letter ID: 0225 Comment ID: 21763 Letter Lines: 811 to 824

Comment Code: 1420 1.2.1.1 Support the GS rulemaking

Comment: CONCLUSION

BP 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 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.) BP applauds EPA’ s willingness to play a significant

38role in this Nation’s strategy to address climate change. We are very supportive of 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: 0225 Comment ID: 21764 Letter Lines: 826 to 836

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 BP’s 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. BP 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 recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of EOR. The GS rulemaking builds upon existing experience and knowledge about safe injection practices in EOR and other injection indus tries, with tailored requirements that address the unique nature of CO2 injection for GS.

EPA acknowledges the comment. Please see the rema inder of EPA's responses to this comment for further details. For additional information on EPA's final regulatory approach, please 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.

39