This comment letter response contains two parts:

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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.

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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).

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• 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.

### Comments of Denbury Resources Inc.

In Response to EPA’s Proposed Rule: Federal Requirements Under the Un derground Injection Control (UIC) Program for Carbon Dioxide (CO 2 

### ) Geologic Sequestration (GS) Wells; Proposed Rule

Docket ID No. EPA

– HQ

– OW

– 20 08

– 0390

(73 Fed. Reg. 43,492 (July 25, 2008))

Submitted December 22, 2008

By Denbury Resources Inc. 5100 Tennyson Pkwy., Suite 3000 Plano, Texas 75024 (972) 673

- 2000 Contact: Ronald T. EvansTable of Contents

I. Introduction

-- and a Suggested Complementary Approach

........................... 1

II. The Proposed Rule would impose undue and unnecessary costs

.................... 6

A. Clarifying the record on “buo yancy”; the scale of current inject io ns and storage ; and corrosion

................................ ................................ .................... 6

1. CO 2 is not inherent ly “buo ya nt ”; rather it is simply denser than some underground gases, fluids or liquids, while less dense than others. Such rel at ive differentials in densit y do not create an upward “f orce” as suggested by the NOPR’s definit io n.

................................ ....................... 7

2. Contrary to s ta

tem ents in the NOPR, the scale of CO 2 inject io ns ant ic ipated to be captured fro m co al

- fi red power will be far less

– not greater

– th an the scale o f exist ing CO 2 injection operations for many years and therefore does not just ify the proposed new regulations at this time.

................................ ................................ ................................ ...... 10

3. The Proposed Rule overstates the corrosivit y of CO 2 , whi ch is not at all corrosive except in the presenc e of free water.

................................ ....... 12

B. The Proposed 50

- year Term for Post

- Inj ect io n S it e Care Is Unreasonably Long

................................ ................................ ................................ ........ 15

III. Any Final Rule Must Clearly Address Potential Exposure under RCRA and CERCLA

................................ ................................ ................................ ........ 17

A. EPA Should Ensure Clarit y Regarding the Possible Coverage of CCS under RCRA

................................ ................................ ................................ ........ 18

B. EPA Should Exclude Inject io n and Geologic Storage of CO 2 from Coverage Under CERCLA

................................ ................................ .......................... 20

IV. Suggested Changes to Language of Proposed Rule

................................ ....... 22

A. § 146.82 Required Class VI permit informat io n

................................ .......... 22

B. §146.84 Area of review and corrective action.

................................ ............. 23

C. § 146.86 Corrosiveness of the carbon dio xide stream, and format io n fluids. 23

D. § 146.87 Logging, sampling, and testing prior to inject io n well operation.

... 25

E. § 146.88 Inject io n well operating requirements.

................................ ........... 28ii

F. § 146.89 Mechanical integrit y.

................................ ................................ .......... 30

G. § 146.90 Testing and monitoring requirements.

................................ ................. 30

H. § 146.92 Inject io n well plugging.

................................ ................................ ...... 32

I. § 146.93 Post

- inject io n site care and site closure.

................................ .............. 32I. I NTRODUCTION

-- AND A S UGGESTED C OMPLEMENTARY A PPROACH

The Proposed Rule is appropriately viewed as part of EPA’s broader effort to address atmospheric emissio ns o f CO 2 and other greenhouse gases (“GHG”). 1 Analysts worl dwide have ident ified carbon capture and storage “CCS” as one of the essent ia l

c om ponents of any successful strategy for lowering such emissions. 2 Wit hin this broader context the Proposed Rule is thus intended to encourage the safe and effective development of geologic storage or sequestration of CO 2 which is in addit io n t o exist ing inject io n and incidental storage of CO 2 in enhanced oil or gas recovery operations (“EOR” or “EGR,” respectively)) through Class II wells. In many respects, the Proposed Rul e appears well

- sui

ted to advance that obj ect ive and EPA deserves credit for having developed a co mprehensive approach to a complex set of issues. In other respects, however, the Proposed Rule appears to misapprehend certain core facts relat ing to the physical properties and behavior of CO 2 in so me u nderground format io ns, the scale of

ex ist ing CO 2 storage operati ons incidental to EOR operations over the last four decades, and the practical fruits of that experience.

As a result, the Proposed Rule includes a number of requirements that long experience has shown are unnecessary for the pr otecti on of underground sources of drinking water (“USDWs”) and a few that would even prove counterproductive. In addi ti on, the Proposed Rule appears to view CO 2 inject io n act ivit y a s a static act ivit y in which CO 2 is injected one time and never leaves th e storage format io n. In contrast, actual experience since 1972 reveals a far more dynamic process in which individual wells may serve as CO 2 inject io n wells, production wells producing o il a nd/or CO 2 , or indeed mult ip le use wells (i.e., inject io n of CO 2 , inject io n of br ine, brine disposal, and producti on). The locational value of injected CO 2 is likely to vary over time as energy and CO 2 markets evo lve and it may well beco me valuable for a Class II EOR well to transi ti on fro m C la ss II to Class VI and then to return to Class II EOR activit y. The Proposed Rules do not seem well suited to deal wit h such dynamic changes in the various int errelated m arkets for CO 2, oil and natural gas.

We are therefore concerned that the Proposed Rule, as presently drafted, w ill increase the cost of geologic storage 3 of CO 2 wi th out producing co mmensurate benefit s

1 See generally Regulating Greenhouse Gas Emissions Und er the Clean Air Act, Advanced Notice of Proposed Rulemaking , EPA

– HQ

– OAR

– 2008

– 0318, 73 Fed. Reg. 44,354, 44,397

- 44,440 (July 30, 2008) (discussing CO 2 emission issues under the Clean Air Act and generally soliciting public comment on how to respond to the U.S. Supreme Court’s decision in Massachusetts v. EPA , 549 U.S. 497 , 127 S. Ct. 1438 (2007) .

2 See, e.g., Intergovernmental Panel on Climate Change, Special Report on Carbon Dioxide Capture and Storage , 208 (Bert, Metz, et al., eds., 2005) (at 13, 45) (“ IPCC Special Report on CCS” ) (showing potential contribution of CCS in reducing emissions).
3 Relative to “sequestration,” the term “storage” has become the more common usage in the worldwide community addressing these issues. See, e.g., the European Uni on’s “Proposal for a Directive of the2

in t erm s o f protecting USDWs. In the case of so me requirements, the Proposed Rule actually tends to diminish the integrit y o f a storage site and thereby increase th e risk of migration o f a CO 2 plume into inappropriate geologic format io ns. Such a result would obviously run direct ly co unter to the Proposed Rule’s fundamental purpose and is not what EPA intends.

We are also concerned that certain unnecessary and cost ly requirements in the Proposed Rule would discourage, or even foreclose, the conversio n of exist ing Class II EOR wells to Class VI geologic sequestration wells. This would undercut the effect iveness of the Proposed Rule’s provisio ns fo r such conversio n. Unnecessary or unduly costly requirements woul d precl ude CCS from playing the role that many po licy analysts and governments worldwide believe that it must play in any successful strategy fo r reducing atmospheric concentrations of CO 2 . This is importan t because it means th at the EPA may

– and indeed, must

– balance objectives that pull at times in co mpet ing di rect io ns. In other words, if the EPA’s primary object ive is to reduce CO 2 emissio ns and if CCS is an essential co mponent of a CO 2 reducti on strat egy, then the rules governing CO 2 inject io n and storage must be crafted in such a way as to advance the primary object ive of reducing GHG emissions.

New rules for CO 2 sequestration that are too risky or too costly for widespread use will work against t his primary overall object ive of reducing GHG emissio ns. Absent a broader legal foundat io n t han the SDWA alone, however, the EPA could conceivably find itself required to impose condit io ns fo r sequestrati on that would foreclose (or unduly limit) the use o f CCS as an emissio ns reduct io n tool. This, we fear, could defeat the very purpose of the rule in the first place. Accordingly, we suggest that EPA examine whether it ma y be appropriate to invoke other exist ing statutory authori ties as part of the legal fo undat io n fo r the new sequestration rules.

Detailed co mments on the Proposed Rule are provided below in Sect io n IV of th ese comments, together with specific suggested changes to the proposed regulatory text th at may help EPA acco mp lish its stated object i ves. Before undertaking that section

- by

sect io n analysis, however, we first suggest that EPA consider adding a complementary set of requi

rements adapted from the current Class II rules that will allow for CO 2 inject io ns and storage of CO 2 at exi st ing EOR si tes to m ore readily transi

ti on to incremental inject io ns and storage following co mp let io n of EOR operations. Those rules shoul d be based on the Class II rules that govern the approximately 45 to 50 millio n tons of CO 2 currently being injected annually i n t he context of EOR operations. 4 Mo reover,

European Parliament and of the Council on the geological storage of carbon dioxide,” (January 23, 2008) and the various reports and recommendations under the UNFCCC’s Clean Development Mechanism (available at http://cd

m.unfccc.int/about/ccs/index.html ) (last visited December 2, 2008). The terms “sequestration” and “storage” are used interchangeably in these comments.

4 The estimate of 44 million metric tonnes per year (as of 2007) is contained among the Technical Supp or ting documents referenced in the Proposed Rule. See Meyer, “Summary of Carbon Dioxide Enhanced Oil Recover y ( CO 2 EOR) Injection Well Technology,” (EPA Document Identification: EPA

HQ

- OW

- 2008

- 0390

- 0018), prepared for the American Petroleum Institute (pub lished by API September 18, 2007), at 5 (Table 3) (noting annual U.S. CO 2 injections of 0.044 GMT) (hereafter “Meyer”). While the Meyer document is not available from regulations.gov, it is published on the Ground Water Protection3

th e rules should also provide for the possibilit y t hat a former EOR well converted to use fo r Cl ass VI CO 2 sequestration may return to EOR oil production if future circumstances make that feasible and desirable

– in effect going from Class II to Class VI to Class II. These rules for incremental storage in exist ing EOR sites would co mp lement the more extensive rules to govern CO 2 inject io ns and storage in saline formations or other less well

- defined underground f orm at io ns.

The Technical Supporting documents already expressly recognize that some o il and gas fields are likely to be good storage site candidates and a “focus of early geo lo gi c sequestration projects”:

[S]om e depleted oil and depleted gas fields al so will likely be considered good candidates for sequestration because they have proven traps and seals and a great deal of exist ing subsurface data. These types of settings have also been used extensively fo r m ethane gas inject io n and storage. It is ant ic ipated that depleted oil and gas reservo ir s will be a focus of early GS projects due to exist ing operati onal experi ence wi th th ese format io ns.

EPA, Technical Supporting Document: Geologic CO 2 Sequestration Techno lo gy and Cost Analysis (June 2008) at 2 (he reafter “EPA Techno lo gy and Cost Analysis”). 5 The same point was made in EPA’s “Cost Analysis for the Proposed Federal Requirements Under the Underground Inject io n Control Program for Carbon Dioxide Geo lo gi c Sequestration Wells (Proposed GS Rule)” (July 2 008), at 1

- 4:

Alt hough the majorit y o f CO 2 is likely to be injected into saline format io ns over th e lo ng term , i

t i s ant ic ipated that, given the experience and the availabilit y of background data and infrastructure related to Class II inject io n, early GS proj ects will likely be in depleted oil and gas reservo ir s.

Moreover, these are the sites that are more likely to be used to receive anthropogenic CO 2 fro m co al

- to

- liquids or ammo nia plants, which are likely to be constructed and operati onal lo ng before m ateri al quant it ie s of CO 2 are captured from coal

- fired electricit y generat ing facilit ies. 6 In addit io n, much of the actual research in examining the

Council’s website at: ht

tp://www.gwpc.org/e

- lib

rary /documents/co2/API%20CO2%20Report.pdf (visited November 10, 2008). As noted below, injections appear to have increased in 2008.

5 EPA Document Identification EPA

- HQ

- OW

- 2008

- 0390

- 0073 , available at: http://www.regulations.gov/f dmspublic/ContentViewer?objectId=09000064806418c4&disposition=attach ment&contentType=pdf (last visited November 10, 2008).
6 Transactions to purchase CO 2 at several such facilities were first announced over two years ago and the development process for these projects is continuing to move forward. See, e.g. , Press Release, Denbury Resources, Inc. “Denbury Resources Inc. Acquires Option to Purchase another Tertiary Flood Candidate; Agreement to Purchase Manufactured Source of CO 2 ” (November 8, 2006); Pre ss Release, Denbury Resources, Inc. “Denbury Signs Agreement to Purchase Additional Manufactured CO 2 ” (June 25, 2007); DKRW Advanced Fuels, LLC, “Medicine Bow Fuel and Power, LLC Fact Sheet”) (coal

- to

- liquids plant planned near Medicine Bow, Wyoming). See also Application for Certification of Hydrogen Energy International, LLC (filed July 31, 2008 with California Energy Commission in docket 08

- AFC

- 8) (proposed IGCC plant to gasify petroleum coke (or blends of petroleum coke and coal, as needed) to4

mo vement of CO 2 plumes in saline format io ns is still in the early stages, with full result s not expected f

or several years, 7 and EPA’s rules may well need to be modified once the resul ts of th ose extensive research projects are obtained.

Under the exist ing UIC rules for Class II wells, however, CO 2 inject io ns at these si tes m ust presum ably cease once the enha nced oil or gas recovery operati ons co me t o an end (because the well would no longer fit the definit io n of a Class II well in the regul at io ns). 8 The Proposed Rule could be modified to provide a transit io nal path for such wells to move from the incidental storage of CO 2 in t he context of EOR operations to the incremental storage of CO 2 captured fro m industrial or power plant sources once th e oil production operations have ended. It is true that these sites would not be adequate to accommodate all o f t he CO 2 th at woul d be captured if such capture techno lo gy were depl oy ed on all new power plants. But even under EPA’s own project io ns in the Cost Analysis, CO 2 captured from power plants is not expected to approach current inject io n quant it ies at any t ime durin g the next 25 years. 9 Hence what is relevant here is that exist ing EOR

- fo cused sites will be generally adequate and available to accommodate
very large quant it ies of those anthropogenic CO 2 supplies that will actually be available fo r sequestrati on for at least the next ten years, if not for twenty or thirty years.

In effect, the Proposed Rule may be missing an opportunit y t o craft a practical transi ti onal pathway th at buil ds on the large scale CO 2 inject io n and storage operations th at are incidental to e xisting EOR operations to incremental storage of CO 2 th at coul d begin fo llo wing terminat io n of a given EOR operatio n. EPA should consider such a transi ti onal pathway from incidental to incremental storage at exist ing well

- defined sites

produce hy

drogen

- rich synthesis gas for power generation while capturing approximately 130,000 Mcf/d of CO 2 to be transported less than 3 miles for use in EOR and sequestration (storage)).

7 See summaries of ongoing DOE

- sponsored research projects on geologic sto rage of CO 2 at: http://www.netl.doe.gov/technologies/carbon_seq/core_rd/storage.html (last visited November 8, 2008).

8 A Class II well is defined in part as a well which injects fluids “[f]or enhanced recover y of oil or natural gas.” 40 C.F.R. § 146.5 (b) (2). Presumably, injections beyond those needed for enhanced recovery of oil

or natural gas would no longer meet this definition.

9 Even after the deployment of the 22 nd pr ojected plant in the year 2030, total CO 2 injections would appear to be signi ficantly less than

– perhaps only half

– the current CO 2 injections for EOR. Compare Mey er, supra , n. 4 wi th EPA, “Cost Analysis for the Proposed Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestratio n Wells (Proposed GS Rule)” (Document EPA

- HQ

- 2008

- 0390

- 0098), at page 3

- 6 (Exhibit 3.1 showing scheduled deployment of projects assumed in the baseline over the 25

- year timeframe) and at page 5

- 37 (Exhibit 5.27 showing projected cumulative injections of 37 3.1 million metric tonnes during study period). See also 73 Fed. Reg. at 43,527 (stating that Cost Analysis assumes that 22 projects will inject 350 Mt CO 2 cumulatively over the next 25 years). This suggests average CO 2 injections from power plants of ap pr oximately 14.92 million metric tonnes per year over the next 25 years, or roughly one

- third the level of current injections of approximately 44 millio n metric tonnes (as estimated by Meyer). See also Table 5, “Baseline Forecast of CO 2 Sequestration Site Startups and Injected Volumes”, in “Technical Support Document: Geologic CO 2 Sequestration Activity Baseline” (June 2008) (Prepared by ICF International) (EPA Document ID No. EPA

- HQ

- OW

- 2008

- 0390

- 0072) (posted by EPA July 25, 2008) (showing annual baseline pr ojection for CO 2 sequestration for twenty

- fi ve year period 2012

- 2036).5

wi th exist ing CO 2 h andling facilit ies as a supplemental or complementary approach to the Proposed Rules.

As current ly crafted, the Proposed Rule may create unnecessary difficult y fo r EPA and the public by focusing init ially on the more difficult future issues raised by pot ential storage of CO 2 in deep saline format io ns, rather than on the much simpler issues th at need to be addressed in the near term to allow for incremental storage of CO 2 in fo rm at io ns where very large quantit ie s of CO 2 are al ready being injected during En hanced Oil Recovery operations. We urge EPA to consider complement ing it s current Proposed Rule with simplified or streamlined procedures that would govern incremental storage of CO 2 at existing EOR or EGR sites fo llo wing the terminat io n of oil or gas
pro duction activit y.

This transit io nal alternat ive could be adopted in place of the current Proposed Rul e that offers a limited transit io n mechanism for Class II wells or as an optional al ternat ive. It should of course include verification, monitoring and si te cl osure requi rements. If successful, the agency could then adapt those rules for less well understood format io ns such as deep saline format ions and unmineable coal seams as the resul ts of ongoing research and the pace of deplo yment of capture techno lo gy fo r el ectri ci ty power pl ants beco me better known.

Accordingly , Denbury urges EPA to better recognize the fruits of exist ing experience wit h inject io n and storage of large vo lu mes of CO 2 th at are necessarily incidental to EOR operations. That exist i ng experience is part icu larly important because it suggests strongly that the init ial CO 2 inject io ns for geologic storage purposes are likely to be made via exist ing Class II wells into previously defined and circumscribed underground oil or gas bearing fo rm at io ns.

We recognize that not all o f t he EOR industry experience will necessarily apply to th e mo vement of CO 2 in saline formations that lack well defined boundaries or physical traps. It is precisely for that reason that it is important to continue research into the behavior of CO 2 pl

umes in such format io ns. Nonetheless, where the CO 2 has already been injected in previously defined reservo ir s using approved well construction techniques and permitted by the proper state authorities, it should be poss ible to continue CO 2 inject io ns fo r geologic storage purposes subject to appropriate addit io nal

mo nit oring, reporti

ng and well clo sure

- rel ated requi rements.6 II. T HE P ROPOSED R ULE WOULD IMPOSE UND UE AND UNNECESSARY C OSTS
BASED ON AN ERRONEOU S UNDERSTAN DING OF ACTUAL FIELD
EXPERIENCE IN INJECT ING CO 2 IN C LASS II WELLS

A. Clarifying the record on “ buoyancy ” ; the scale of current injections and storage; and corrosion

The U.S. Court of Appeals for the D.C. Circuit has famously

– and repeatedly

– observed that there are some issues encountered by admi nistrative agencies where “a

mo nt h of experience will be worth a year of hearings.” 10 In the case of CO 2 inject io n and incidental storage during EOR operations, the state permitt ing agencies and the oil and gas industry do not have a mere month of experien ce, but nearly four decades’ worth. According to the documents in the current record, state permitting authorit ie s have issued permits for approximately 13,000 Class II wells to inject CO 2 fo r EOR operati ons, over 6,000 of which are actively inject ing eac h year in excess of 44 millio n met ri c tonnes of CO 2
. 11 While that experience is focused on inject io ns into well

- defined oil and gas bearing format io ns, rather than saline format io ns, many of the operational lessons learned rel ate di rect ly t o appropriate w ell construction requirements for CO 2 inject io n wells, corrosi on management for inject io n and production wells, as well as pipelines and associ ated CO 2 handling facilit ies. We respect fu lly urge EPA to give greater weight to th at extensive real

- worl d exper ience than currently given under the Proposed Rule.

The NOPR appears to downplay such actual experience in the belief that the

vo lu mes, pressures, and certain physical characteristics of the CO 2 injectate for geologic storage are “unique.” 12 The basis for th e belief that CO 2 injectate for geologic storage is “u nique” is apparent ly ba sed on three specific factors:

10 American Airlines, Inc. v. Civil Aeronautics Board , 359 F.2d 624, 633 (D.C. Cir., 1966) cert. denied

, 385 U.S. 843, 87 S. Ct. 73, 17 L. Ed. 2d 75 (1966) (opinion en banc by Levan thal, J.). Judge Levanthal’s opinio n has been applied in numerous cases involving a number of regulatory schemes including, for example, natural gas regulation ( American Public Gas Ass'n v. Federal Power Commission , 567 F.2d 1016, 1032 (D.C. Cir. 1977) an d Maryland People's Counsel v. F.E.R.C ., 761 F.2d 768, 779 (D.C. Cir. 1985) (same, but finding FERC program insufficiently explained or supported)); communications regulation ( United Telegraph Workers, AFL

- CIO v. F.C.C ., 436 F.2d 920, 925 (D.C. Cir. 1970)) ; and commodities regulation ( Commodity Exchange v. Commodity Futures Trading Comm’n , 543 F. Supp. 1340, 1351 (S.D.N.Y., 1982)).

11 Mey er, supra , n.4, at 2 (EPA Document Identification: EPA

- HQ

- OW

- 2008

- 0390

- 0018). See also John A. Veil and Markus G. Puder, “Evaluation of State and Regional Resource Needs to Manage Carbon Sequestration through Injection” (June 2007) (EPA Document Identification EPA

- HQ

- OW

- 2008

- 0390

- 0084.pdf) (available also from the Ground Water Protection Council’s website at: http://www.gwpc .org/e

library /e

- library _documents/e

- library

_documents_co2/Argonne%20Report%20CO2%20Resources.pdf (last visited November 10, 2008) at 8 (Table 3) (listing CO 2 injection wells by state and by UIC well class)). The number of active CO 2 injection wells is al so published in the Annual Production Report, Oil & Gas Journal, vol. 106, (Apr. 21, 2008).
12 The term “unique” is ubiquitous in the Proposed Rule in describing CO 2 injections for geologic storage. See e.g., NOPR, supra , 73 Fed. Reg. at 43,492, 43,495, 43,502, 43,504, etc.7 (a) th e “buo ya nt ” nature of CO 2 ; 13 (b) th e large scale of CO 2 inject io ns ant ic ipated to be captured fro m co al

- fi red power plants as compared to C O 2 inject io ns fo r EOR purposes; 14 and (c) th e corrosivit y of CO 2 in t he presence of free water. 15

The Proposed Rule thus states that the regulatory alternat ive selected was chosen

“ because of th e vo lu mes of CO 2 being ant ic ipated for long

- term storage, the b uoyant and viscous nature of the injectate, and its corrosivit y when mixed with water.” 73 Fed Reg. at 43,504 (emphasis added). As shown below, however, the Proposed Rule mischaracterizes key facts with regard to these points.

1. CO 2 is not inherently “buoyant”; rather it is simply denser than some underground gases, fluids or liquids, w hile less dense than others. Such relative differentials in density do not create an upw

ard “force” as suggested by the NOPR’s definition.

The pream

ble to the Proposed Rule makes very clear that the changes to the UIC program for CO 2 sequestration are based on the assertion that CO 2 is “buo ya nt .” 16 Thi s is simply incorrect. CO 2 is a non

- expl osive, non

- flammable, non

- tox ic gas that possesses different physical properties than so me o th er injectates. These physical properties do not

13 See citations at n. 16 infra

.
14 See citations at n. 19 infra . See also EPA Cost Analysis, supra , at page 3

- 4 (stating that volumes to be injected for GS are “much greater” than traditionally seen in enhanced oil and gas recove ry operations, “which currently inject CO 2 on a relatively small scale.”)

15 See citations at n. 26 infra

.
16 See, e.g., 73 Fed Reg. at 43,493 (defining buoyancy as “[u]pward force on one phase (e.g., a fluid) produced by the surrounding fluid (e.g., a liq uid or a gas) in which it is fully or partially immersed, caused by differences in pressure or density); 73 Fed. Reg. at 43,494 (stating that physical trapping occurs “when buoyant CO 2 rises in the formation until it reaches a layer that inhibits further u pward migration or is immobilized in pore spaces due to capillary forces”), at 43,495 (same); at 43,499 (EPA evaluated risks of CO 2 injection to USDWs to determine how best to tailor the existing UIC regulations “to address the buoyant and viscous properti es of CO 2 and the large volumes that could be injected); at 43,504 (EPA proposing changes “because of” the volumes of CO 2 anticipated for long

- term storage, the buoyant and viscous nature of the injectate, and its corrosivity when mixed with water); at 43 ,505 (stating that “buoyancy of CO 2 necessitates good characterization of potential conduits for fluid migration upward through the confining system to USDWs); at 43,506 (referencing the “complex multi

- phase buoyant flow of the CO 2 ”); id . (stating that co mputational models used to delineate the area of review consider inter alia the “buoyant nature” of the injected CO 2 ); at 43,509 (basing proposed enhancement to deep well construction procedures “[d]ue to the buoyancy of CO 2 ” in order to provide additional barriers to CO 2 leakage outside of the injection zone); at 43,512 (“buoyancy of CO 2 ” and large volumes may warrant improved leak detection of geologic storage wells even though use of tracers is not included in existing deep well requirements); at 43,513 (current mechanical integrity testing requirements will need to be tailored for CO 2 storage to address the “unique properties of CO 2 , specifically its buoyancy and potential corrosivity”); id. (same, referencing need for tailored testing requirements “be cause of the buoyant and corrosive properties” of the CO 2 injectate stream); at 43,514 (basing increase in frequency of mechanical integrity testing in part on the “buoyant nature of the injected fluid that tends to force it upward toward USDWs”); at 43,51 9 (stating that area over which CO 2 will spread is likely to be larger than for existing well classes “[g]iven the buoyancy of CO 2 , viscosity, and large injection volumes” associated with geologic storage of CO 2 ); and at 43,528 (stating that current regula tory requirements do not specifically consider “injection of a buoyant corrosive fluid”).8

include any special buo ya ncy characterist ics or properties. Rather, CO 2 is simply more dense than so me u nderground fluids or gases and less dense than others. Hence the

mo vement of injected CO 2 in a reservo ir , or any ty pe of system containing different flui ds or gases, will vary based on the relative densit ies of the various fluids or gases that are in the reservoir. The various materials will simply segregate based on the rel at ive densit ie s of the fluids or gases including the CO 2 . As a result, CO 2 ma y be the fluid that sinks to the bottom, rises to the top, or resides so mewhere in between the top and the bottom fluids within the system.

For example, if CO 2 is in

jected in a system that contains water then the CO 2 will at l east init ia lly rise to the top of the sy stem . This seems to be the situation that the Proposed Rule assumes will always be the case. However, if CO 2 is injected into a system th at contains natural ga s ( i.e., met hane), the CO 2 will sink to the bottom of the system , below the natural gas, which will remain on top. That does not mean that the methane has suddenly beco me “buo ya nt ” as defined by the Proposed Rule or exerts any incremental “upward force.” Nor does it mean that CO 2 acquires some special dow nw ard fo rce. It simply means that natural gas is relatively less dense than the CO 2 and hence the
tw o substances will tend to separate with the natural gas above the CO 2 . To rei terate: the rel at ive dep th s, pressures and fluids within the system will determine the densit ies of the flui ds wi thin the system and the relat ive location of each fluid within the system. CO 2 has no special or unique “buo ya ncy” that causes it to exert an independent “force” in a n underground reservo ir

. This is recognized in the technical supporting documents for the Proposed Rule. For example, the Vulnerabilit y E valuati on Framework 17 explains that:

Supercrit ic al CO 2 is less dense and more buo ya nt than o il a nd 30% to 50% more b uoy ant than sal

twater. As a result, injected supercrit ical CO 2 will rise to the top of depl eted oil or deep saline format io ns. In contrast, supercrit ic al CO 2 is denser th an natural gas, and will sink when injected in depleted gas reservo ir s. As
tem peratur e increases, the densit y o f supercrit ical CO 2 decreases at a given pressure, but increases wit h increasing pressure at a given temperature. Similarly, th e viscosit y o f supercrit ical CO 2 decreases with increasing temperature at a given pressure, but increas es wit h increasing pressure at a given temperature. As
tem perature and pressure increase with subsurface depth, the densit y and viscosit y of supercri

ti cal CO 2 injected will be determined by the specific pressure and
tem perature condit io ns. Finally, when CO 2 disso lves, it shares the physical properties of the substrate (e.g., saltwater) and no longer behaves independent ly.

The Proposed Rule does not incorporate this understanding, and instead appears predi cated on the perception that CO 2 exercises an upward force , as stated in the definit io n o f t he term “buo ya ncy” in the Proposed Rule. The Proposed Rule defines “buo ya ncy” as:

17 EPA, “Vulnerability Evaluation Framework for Geologic Sequestration of Carbon Dioxide” (July 10, 2008) at 76

- 77 (Appendix A) (internal citations omitted).9 upward force on one phase (e.g., a fluid) produced by the surrounding fluid (e.g., a liquid or gas) in which it is fully or partiall y i mmersed, caused by differences in pressure or densit y.

73 Fed. Reg. at 43,493 (emphasis added). This use of the word “force” is scient ifically inaccurate and generates connotations that there are addit io nal forces created when CO 2 is injected into the subsurface for sequestration. This is not the case, however, as there are no addit io nal or different forces associated with CO 2 inject io ns than there are with the inject io n of any other fluid or gas. The inject io n of any fluid into the subsurface create s a transi ent pressure wave that is greater at the injection site and diminishes significant ly at posi ti ons l ocated away fro m t he inject io n site. The separation of fluids wit hin a fo rm at io n due to their relat ive densit ies does not create any new or additi onal fo rces.

Much of the proposed rule appears to focus on the inject io n of CO 2 int o deep saline format io ns. In these format io ns, the injected CO 2 wo uld indeed tend to be rel at ively less dense than the exist ing saline fluids and hence the saline fluids w oul d tend to sink towards the bottom of the format io n relat ive to the CO 2 and so migrate underneath th e CO 2 . Thi s tendency of saline fluids to segregate out below the CO 2 does not endow th e CO 2 wit h any buo ya nt fo rce, however. The issue is not “buo ya ncy, ” but merely the
ant ic ipated movement of the CO 2 in a particular geologic format io n relat ive to other fo rm at io n fluids.

In the NOPR’s discussio n of regulatory alternatives considered by EPA, the “buo ya nt and viscous nature of the injectate” is cit ed as a key reason why “...EPA is proposing changes to the exist ing UIC approach or requirements in several program areas...” 73 Fed. Reg. 43,504. This misunderstanding of how injected CO 2 behaves underground is repeated at mult iple points in Sections 1, 2, 3, 4, 5 and 8. 18 The fact that th e si gnificant new regulatory regime set forth in the Proposed Rule is based to such a great extent on factually and technically erroneous informat io n is of serious concern.

EPA should acknowledge this error and correct the factua l predicate for its assumpt io n t hat CO 2 som ehow “wants to get out” of the storage format io n. Taken together with addit io nal better informed assumpt io ns on which the rule is based (di scussed below), this necessarily should lead EPA to find the exist ing UIC methodol ogi es and rules generally sufficient to address CO 2 inject io ns fo r geol ogic storage in oil and gas bearing format io ns. In other words, Class II regulat io ns and requi rements shoul d be used with the addit io n of requirements for long term monitoring if, for example, an operator of a well desires to convert an operation to a geologic storage si te at the terminat io n of EOR operations. Class II regulat io ns and requirements have proven successful in protecting underground sources of drinking water for a lmo st 40 years and thus modificat io ns or addit io ns are more appropriate than establishing a

com pletely new well classificat io n.

18 See citations in note 16, supra . The other primary reasons for which a special rule is required for CO 2 are the large volumes, and the corrosive nature of the CO 2 injectate, which are discussed below.10

2. Contrary to statements in the NOPR, the scale of CO 2 injections anticipated to be captured from coal

-

fired pow er w ill be fa r less

– not greater

– than the scale of existing CO 2 injection operations for many years and therefore does not justify the proposed new regulations at this time

. The second basis for the Propose d Rule’s conclusion that CO 2 injections for geol ogi c storage are “unique” is the statement that the scale o f t hese inject io ns will be on a scale that is much larger than other types of UIC inject io n operations. 19 Thi s is simply erroneous. For example, the EPA Cost Analysis assumes cumulat ive injections of 350 millio n metric tons of CO 2 over the next 25 years. 20 Yet as the NOPR itself recognizes, thi s is only about half th e quantit y o f CO 2 th at has already been injected in oil and gas producti on operati ons

– fo r as the NOPR notes (at 43 Fed. Reg. 43,503) a study prepared fo r the American Petroleum Inst it ute estimated in 2007 that some 600 millio n met ri c tonnes had already been injected. The study referenced by the Proposed Rule further evaluated current ann

ual inject io ns at approximately 44 millio n metric tones per year. 21 These quant it ies have been increasing in recent years. For example by early 2008, Denbury al one was producing and transporting over 700,000 Mcf/d of CO 2
– th e equivalent of approximately 13.4 millio n met ri c tonnes

-- th e great majorit y o f w hich was injected for EOR operations. 22 In other words, the scale o f o perations of this one

com pany

– which is not the largest participant in the EOR industry

– is essent ia lly th e same by itself as EPA’s proj ected average inject io n rate for geologic storage for the ent ir e nat io n of 14 millio n tonnes per year over the next 25 years (as published in the NOPR’s Cost Analysis (350 millio n metric tonnes cumulat ive inject io ns over 25 years divided by 25 years = 14 millio n tonnes per year)). 23

19 See, e.g., 73 Fed. Reg. 43,506 (stating that it is “g enerally agreed” that over time, the CO 2 plume and pressure front associated with a full

- scale GS project will be “much larger” than for other types of UIC injection operations); 73 Fed. Reg. at 43,518 (requirement to address the “unique and large

- scale na ture of CO 2 GS operations”); and 73 Fed. Reg. at 43,527 (stating that Cost Analysis assumes that 22 projects will inject 350 Mt CO 2 cumulatively over the next 25 years). See also EPA Cost Analysis, supra , at page 3

- 4. (stating that volumes to be injected for GS are “much greater” than traditionally seen in enhanced oil and
gas recover y operations, “which currently inject CO 2 on a relatively small scale”).

20 73 Fed. Reg. at 43,527. This estimate is within the range of other published estimates. For exampl e, the IPCC Special Report in 2005 estimated CO 2 pipeline transport in the U.S. (most of which is injected for EOR purposes) at 50 million metric tonnes per year and separately estimated CO 2 injections for EOR at about 30 million metric tonnes per year. I PCC Special Report, at 181 (for transport) and at 203 (for injection)

21 Meyer, supra , n. 4 “Summary of Carbon Dioxide Enhanced Oil Recover y ( CO 2 EOR) Injection Well Technology,” prepared for the American Petroleum Institute (published by API September 18, 2007), at 5 (Table 3) (note stating 0.044 GMT of CO 2 injected per year) (EPA Document EPA

- HQ

- OW

- 2008

- 0390

- 0018). As noted above, the report is not accessible through the regulations.gov website, but may be accessed either from the Ground Water Protection Council’s website at: http://www.gwpc.org/e

library /documents/co2/API%20CO2%20Report.pdf (visited November 10, 2008) or from the American Petroleum Institute at http://www.api.org/aboutoilgas/sectors/explore/upload/API_CO2_Report_August

2007.pdf (last vis ited November 17, 2008).

22 See 2007 Annual Report of Denbury Resources, Inc. (Form 10

- K), at 6 (converting Mcf to metric tonnes by dividing by 19.1).

23 See references in note 9, supra

.11 Put another way , at current rates, the nation’s EOR operators will inject more CO 2 through Class II wells in the next 7 or 8 years than the total quantities of CO 2 projected to be injected via the new Class VI wells over th e next 25 years

– assuming th at CO 2 capture at power plants is in fact deplo ye d on a commercial scale during that time. In sum, the new requirements in the Proposed Rule cannot be supported on the erroneous statement that CO 2 inject io ns under Class VI rul es will be materially greater th an those under the current Class II rules, when the reverse is true today and (accept ing EPA’s own estimates for the future rate of deplo yment of carbon capture techno lo gy at power plants) is expected to remain the case for decades. It is only in some distant future th at injections of powerplant CO 2 are anticipated to approach the scale of current operati ons (which may also expand). Hence the simple scale of CO 2 injection operations of captured CO 2 is not ”unique” and is not expected to become a relevant dist inct io n fo r at l east the next several decades.

Si milarly, where the Proposed Rule states that it is “generally agreed” that over time the CO 2 plume and pressure front associated with a full

- scale GS project will be

muc h larger than for other types of UIC inject io n operations

, 24 this statem ent is not borne out by th e facts. While not defined in the Proposed Rule, a “full

- scale” GS project might, fo r example, be a project capable o f acco mmo dating the CO 2 captured from a 500 MW power plant, or roughly 2.4 millio n metric tonnes per year 25

– an average o f just 6,575 metri c tonnes per day . Thi s am ounts to l ess than 5 percent

-- one

- twenti eth

-- th e level o f current Class II CO 2 inject io ns (50 millio n met ri c tonnes divided by 2.4 millio n = 0.048). It i s thus simply not accurate to conclude that it is “generally agreed” the CO 2 pl ume and pressure front of a full

- scale GS project will be “much larger” than for CO 2 inject io ns fo r EOR purposes; the facts are quite the reverse: The scale of current CO 2 inject io ns through exist ing Class II wells is already vastly larger than the scale o f t he CO 2 inject io ns expected for the new Class VI wells for the foreseeable future.

This does not mean that there will be no differences between CO 2 inject io ns fo r geol ogi c storage versus EOR operations, or that new rules are not appropriate for long
term sequestration, especially when dealing wit h deep saline format io ns for storage. However, it does strongly suggest that what is needed today is not so much a fully developed set of rules to govern injections of power plant CO 2 int o saline format io ns, as a framework for allowing the transit io n o f t he exist ing and planned universe of CO 2 wells fro m E OR operations to long term geo lo gi c sequestrati on ope rations. Further development of rules for inject ing and storing CO 2 in non

- oil and gas bearing format io ns such as deep saline formations could then be undertaken. At that point, such rules would properly be based on addit io nal years of research regarding th e mo vement of a CO 2

24 73 Fed. Reg. at 43,506.

25 The estimate of 3 million metric t onnes per year output of CO 2 from a 500 MW plant is taken from the MIT report, “The Future Of Coal: Options For A Carbon

- Constrained World” at 24

- 39, (hereafter “The Future of Coal”) at 105 (available at http://web.mit.edu/coal/ (last visited May 6, 2008) ). Assuming that 80 percent of the CO 2 output were captured, there would be 2.4 million Mt CO 2 available for injection and storage.12

pl ume in a saline format io n, the experience of the state Directors with monitoring and

rem ediat io n activit ies, etc.

3. The Proposed Rule overstates the corrosivity of CO 2 , w hich is not at all corrosive except in the presence of fr ee w ater.

The third basis for the Proposed Rule is the potential corrosivit y of CO 2
. 26 The Proposed Rule speci fically seeks comment regarding requirements for degradation

resistant well construction materials, such as acid

- resistant cements and corrosion

resistant casing. The NOPR correctly states that CO 2 mixed wit h water will form carbonic acid (H 2 CO 3 ) and tha t carbonic acid is corrosive of cement

-- a fact that has long been taken into account in exist ing permitting procedures and industry practices. However, the preamble to the Proposed Rule appears to overstate the corrosivit y o f CO 2 under actual geologic s torage condi ti ons. For example, the NOPR references (73 Fed. at 43,510) the actual field experience and observat io ns from wells that had been exposed to a CO 2 - water environment for 30 years, but then appears to largely dismiss the results on th e grounds t hat this actual field corrosion experience is “surprisingly” low (presumably in light of a referenced laboratory study th at f ound m uch m ore rapi d corrosi on than has in fact been experienced). 27 In con trast, a study th at reviewed actual samples exposed to

a CO 2 - water environment for 30 years was seemingly dismissed as invo lving “only limited examples,” while the contradictory laboratory study was apparent ly given greater wei ght. 28

The Proposed Rule appears to downplay other research publications that conclu de th at convent io nal Portland

- based well cements have been adequate to guard against corrosi on from CO 2 mixed with water. For example, the Proposed Rule cites Meyer (2007) 29 , but doesn’t recognize that Meyer notes that non

- Portl and cements have not been wi dely used in CO 2 EOR applications, and have been applied instead to resist “very severe acid gas (CO 2 and H 2 S) and highly corrosive geothermal brine exposure condi ti ons.” Meyer (2007), supra , n. 4 at 18. Dr. Meyer also noted the actual experience fro m a 52 year old well wit h convent io nal, Portland

- based well cement, that had been exposed to CO 2 fo r 30 y ears in EOR operations and no significant wellbore failure had

26 See 73 Fed. Reg. at 43,503 (design changes are being proposed to address mobility “and corrosivity” caused by long term G S of CO 2 ); id ., at 43,504 (EPA proposing changes “[b]ecause of” the volumes of CO 2 being anticipated for long

- term storage, the buoyant and viscous nature of the injectate, “and its corrosivity wh en mixed with water”); id . at 43,509 (pointing to the “poten tially corrosive nature of the injectate” in the design and construction of CO 2 GS wells and noting that “CO 2 mixed with water or impurities (NO X , SO X and H 2 S) can be corrosive to well materials and cements” and expressing concern that “conventional”

cemen t formations (e.g. Portland cement) are “potentially vulnerable” to acid attack).

27 73 Fed. Reg., at 43,510

28 Id . (“[a]though the field corrosion looks surprisingly low, these are only limited examples. Laboratory studies are conducted under aggres sive chemical conditions in an attempt to mimic the cumulative effects of long

- term exposure to CO 2 - rich formation fluids. Given the high injection rates, long lifespan, and potential impurities in GS, careful selection of acid

- resistant materials and prac tices may be necessary).

29 Meyer, supra , n.4.13

been observed. Id . (referencing Carey, et al. 2007). 30 Indeed, Carey, et al., concluded fro m th e review of actual cement exposed to CO 2 for 30 years that “[t]he casing was in excellent condit io n and showed litt le evidence of corrosion.” Carey, et al., at 76. While th e Portland cement did show evidence o f exposure to CO 2 , the structural integrit y o f t he recovered cement core, petrographic observat io ns, air permeameter data, and cement bond log indicated that “the cement retained its capacit y t o prevent significant transport of fluid through the cement matrix.” Id . at 84; see also at 78 (“no obvi ous evidence for CO 2 int eracti on” in the shale caprock); id . (core bond log showed “no evidence o f CO 2 - induced de

- bonding or channel format io n at or near the reservo ir contact”); id . (“most basic observation o f t he SACROC core” is that the Portland cement at th e studied well “survived and retained its structural integrity after 30 years in a CO 2 - reservo ir environment”).

Finally , the record here should be supplemented wit h addit io nal laboratory research published after the Proposed Rule, the results of wh ich suggest a rate of degradation of Portland cement under condit io ns mimicking geological sequestration that is far less than the study cited in the Proposed Rule. See Kutchko, et al. “Rate of CO 2 At tack on Class H Well Cement under Geologic Sequestratio n Condit io ns” (hereafter Kutchko, 2008). 31 While the details of the research merit careful considerat io n, and addi ti onal research is current ly u nderway, the conclusio n of this August 2008 research publicat io n is worth quoting:

Based on the alteration pr ocess, penetration depths, and rates of alteration observed in this study, and on penetration depths observed in field samples exposed to CO 2 fo r ~30 y ears, it is unlikely that alteration of these cements via

cem ent m atrix diffusio n of supercrit ical CO 2 or CO 2 - saturated brine would lead to si gnificant al

terati on in well co mp let io ns that are properly cemented with Class H neat cement after decades of exposure to supercrit ical CO 2 or CO 2 - ri ch brine.

Kutchko, et al.(2008), supra , at 6242.

This research i s reinforced by other papers presented at a major internat io nal conference on greenhouse gas control techno lo gi es, the 9th International Conference on Greenhouse Gas Control Techno lo gies (hereafter cited as “GHGT

- 9”) that we commend to the agency’s attenti on, including in particular: 32

30 Dr. Meyer references the pre

- publication version of Carey, J.W., M. Wigand, S.J. Chipera, G. WoldeGabriel, R. Pawar, P.C. Lichtner, S.C. Wehner M.A. Raines and G.D. Gutherie Jr., “Analysis and Performa nce of Oil Well Cement with 30 Years of CO 2 Expo sure from the SACROC Unit, West Texas, USA,” preprint submitted to International Journal of Greenhouse Gas Control, October 18, 2006. The citation to the published report is 1 International Journal of Greenh ouse Gas Control, pages 75

- 85 (2007).

31 Barbara G. Kutchko, Brian R. Strazisar, Gregory V. Lowr y, David A. Dzombak, and Niels Thaulow, “Rate of CO 2 Attack on Class H Well Cement under Geologic Sequestration Conditions,” Environmental Science and Technol ogy, vol. 42, number 16 (August 15, 2008), at 6237

- 42.

32 “GHGT

- 9, 9th International Conference on Greenhouse Gas Control Technologies,” (November 16

- 20, 2008) Washington DC ( http://mit.edu/ghgt9/ ) (hereafter “GHGT

- 9 Conference” (organized by MIT in colla boration with the IEA Greenhouse Gas R&D Programme (IEA GHG), with major sponsorship from the U.S. Department of Energy). All papers presented at the GHGT

- 9 Conference are available from the14

· Dugui d, “An est imate of the time to degrade the cement sheath in a well exposed to carbonated brine,” summarizing (at 3

- 4) recent physical research on cement carbonat io n and describing own research. In sum, Duguid’s recent experiments indicate (at 8) that for a well that has good zonal isolat io n and no pathways for fl ow, “the rate of degradation will be between 30,000 and 700,000 years to degrade 25 mm o f neat paste in a sandstone reservoir, and possibly lo nger to destroy th e cement passing through the cap rock.” 33

· Crow, Williams, Carey, Celia, and Gasda, “Wellbo re integrit y analys is of a natural CO 2 producer,” at 8 (concluding, inter alia fro m a nalysis o f 30 year old well fro m a natural CO 2 producti on reservo ir th at Portl and

- based cement sy stems “can be used effect ively in creating suitable barrier systems for long

- term CO 2 storage operati ons, if good practices are emplo yed during well construction”);

· Benge, “Improving wellbore seal integrit y in CO 2 inject io n wells” (reviewi ng recent research and noting (at 2) that applying the formula developed by Barlet

Gouedard, et al., it would take “several hundred centuries”

– tens of thousands o f
years

-- to degrade 6 meters of wellbore cement (even assuming a continuous and renewable supply of fresh CO 2 wi th no other inhibit ing reactions occurring).

· Aiken, “An Introduction to the IEA GHG International Research Network on Wellbore Integrit y. ” The paper reviews the work of the IEA’s Internat io nal Research Network on Wellbore Integrit y fo unded some 4 years ago and noting (at 1, 6) the importance of analyz ing the differences found between laboratory experiments and corresponding field findings, and if necessary, designing new laboratory experiments to better replicate field condit io ns.

A great deal of other original research was presented as well, underlining the dynamic nature of research in this area and reinforcing the importance of avo id ing overly

prescri pt ive requirements that are unnecessary based on experience in the field.

We concur wi

th th e Proposed Rule’s general principle that cement and cement addi ti ves must be “co mpat ible with the carbon dio xide stream and format io n fluids” and “o f su fficient qualit y a nd quant it y t o maintain integrity over the design life” (Section 146.86 (b) (5)). However, we are concerned that the rule contains prescript ive well construction and monitoring requirements that do not appear necessary in light of actual field experience and the more recent laboratory research referenced above. At a minimum, th e mo re recent research suggests that EPA should defer imposing these

conference website at: http://mit.edu/ghgt9/papers/index.html (l ast visited December 12, 2008) and through the site’s search portal at: https://www4.eventsinteractive.com/iea/rs.esp?id=270005&scriptid=sppp1 (last visited December 12, 2008).

33 It should be noted that these results are quite different than in a 2006 pa per by some of the same researchers which EPA included among the supporting materials in this proceeding. Compare A. Duguid, M. Radonjic, R. Bruant, T. Mandecki, G. Scherer, and M. Celia “The Effect Of CO 2 Sequestration On Oil Well Cements” (Document ID: EPA

- HQ

- OW

- 2008

- 0390

- 0013) (posted by EPA July 25, 2008).15

addi ti onal costly requirements pending the fruits of the further field experience and research.

We would also call to EPA’s attention other recent research fro m t he GHGT

- 9 Conferen ce that is relevant to this rulemaking wit h regard to the carbon content of oil that coul d be produced via CO 2 inject io n of captured CO 2 emissio ns. Ferguson, et al. reviewed the net carbon content of oil produced via CO 2 - based EOR, taking into account th e storage of residual CO 2 th at rem ains stored as a normal incident of EOR production operati ons. The researchers calculated that oil produced through inject io n of captured CO 2 emissio ns would be roughly 70 percent “carbon free” under current techno lo gy

. See Ferguson, Nicho ls, Leeuwen, and Kuuskraa, “Storing CO 2 wi th Enhanced Oil Recovery” (“Ferguson, et al. 2008”) 34 The authors estimate that next generation CO 2 storage techno lo gy may allow for the produced oil to be “100+” percent carbon free and evaluat e th e potenti al size of the market for CO 2 fo r these EOR purposes on the order of 7,500 millio n metric tonnes between now and 2030. This capabilit y of the U.S. oil industry to reduce the net carbon content of new o il supplies is an aspect of the sequestra ti on debate th at is not addressed in the Proposed Rule, but illustrates how targeted technological inno vat io n can reduce carbon emissio ns while maintaining

– indeed, growing

– energy supply.

B. The Proposed 50

- year Term for Post

- Injection Site Care Is Unreasonably Long

Denbury strongly objects to the use of a 50

- year timeframe for continuous

mo nit oring during post

- injection site care. Our object io n ste ms fro m t he relative risks associ ated wi

th th e vari ous phases of geol ogic storage operati ons, the recognized progression of various geologic trapping mechanisms (which means that risks of unexpected migrat io n diminish over time), the creation of artificial impediments to financial assurance and the sagacit y of other regulatory proposals.

Fi rst, we believe that published and reputable lit erature suggests that a 50

- year timeframe for post

- inject io n site care is too long and who lly unrelated to the risks

as soci ated wi

th geo lo gi c storage. For well

- si ted, characterized, operated and managed si tes, the risks accumulate during the operati onal phase, but decline as sites mo ve fro m post

- inject io n site care to closure to eventual long

- te rm care. Prevailing scient ific opinio n expects the risk profile to diminish wit h t ime. 35 As Lindene and Trabucchi suggest, “the risk of so me events occurring that result in an unexpected release of carbon

34 Paper presented at GHGT

- 9 Conference and available from the GHGT

- 9 Conference website cited above.

35 See Intergovernmental Panel on Climate Change, Special Report on Carbon Dioxide Capture an d Storage , 208 (Bert, Metz, et al. eds., 2005); see also Sally Benson, “Carbon Dioxide Capture and Storage: Research Pathways, Progress and Potential,” Global Climate & Energy Project Annual Symposium, October 2007, available at http://pangea.stanford.edu /research/bensonlab/presentations/Carbon%20Dioxide%20Capture%20and%20St

or age%20

- %20Research%20Pathways%20Progress%20and%20Potential.pdf (hereafter “Benson 2007”).16

di oxide more than 10 years after terminat io n of injection will beco me increas ingly remote due to geochemistry condi ti on s. ” 36 T he geochemistry condi ti ons they reference include th e four main mechanisms which trap CO 2 in well

- chosen geo lo gi cal fo rm at io ns

– 1) structural trapping

-- which is addressed in the proposed rule and is not n ecessary to di scuss further here; 2) residual CO 2 trapping

-- where CO 2 is trapped by capillary forces in the interst ices of the rock format io n, a process which develops about 10 years after inject io n; 3) dissolution or solubility trapping

-- where the CO 2 dissolves into the brine fo und in the geo lo gi cal format io n and sinks because the CO 2 saturated brine is more dense than non

- CO 2 saturated brine, a process taking place between 10 and 100 years af ter inject io n; and finally, 4) mineralization or mineral tra pping

-- which occurs when di ssolved CO 2 chemically reacts wi th the form at ion rock to produce minerals, a process requi ri ng hundreds of years. 37

Given that the greatest risk of a release occurs during the operational stage of a storage project, and that resi dual and dissolut io n trapping start well in advance of 50 years, it is difficult to understand why a 50

- year timeframe for post

- inject io n site care was chosen. A 50

- year post

- inject io n site care timeframe simply does not correlate to the rel at ive r isk s associ ated wi th geo lo gi cal storage and the function o f geo lo gic trapping mechanisms that limit the risk of unexpected releases o f CO 2 af ter the terminat io n o f inject io n act ivit y.

Furtherm ore, other respected m odels use a much shorter period. For inst ance, the IOGCC Model Rules and Legislat io n st ipulate a 10 year post

- inject io n site care period. 38 Under the IOGCC Model, the operator of the storage site is the responsible part y a nd is requi red to m aintain an operational bond fo r the equivalent of a post

- inject io n site care peri od and unt il clo sure. This 10 year post

- inje cti on si te care peri od is more plainly rel ated to the rel ative risks o f geo lo gi c storage and the geochemical react io ns discussed above. Also, in the preamble, EPA acknowledges that a 30

- ye ar post

- clo sure care period is recognized as the industry standard for the injectio n of hazardous waste. 39

Finally , this 50

- year t imeframe raises barriers to obtaining financial assurance for prospective projects. Section 146.85 of the Proposed Rule re quires the owner or operator
to m aintain financial responsibilit y fo r corrective act io n, inject io n well plugging, post

inject io n site care and site closure. Undoubtedly owners/operators will e nt er the private sector financial assurance market for some per io d in order to meet this requirement. An

36 Chiara Trabucchi and Lindene Patton, “Storing Carbon: Options for Liability Risk Managemen t, Financial Responsibility,” Daily Environment Report, Bureau of National Affairs , pg. 8 (Sept. 3, 2008).

37 See IPCC Special Report on CCS, supra n.2 , at 208; see also Benson 2007, supra n.35

.
38 See generally IOGCC, “Storage of Carbon Dioxide in Geolo gic Structures: A Legal and Regulatory Guide for States and Provinces” (September 2007) (publishing Model Statute and Rules for CO 2 storage). The proposed 10 year default period for maintaining operator responsibility is at Model General Rules and Regul ations, Section 2.0 (f) (defining “CSP Closure Period” as 10 years unless otherwise designated by the State Regulatory Agency). See also at Section 4.0 (b) (10) (requiring performance bond to be maintained for 10 years after closure of the facility in acc or dance with Section 9.0). The discussion of the Model Statute and Regulation also mentions other potential periods of “10 or 29 years, etc.” IOGCC
, supra , at 30.
39 See 73 Fed. Reg. at 43,510.17

uncertain or a 50

- year post

- inject io n site care timeframe creates impediments to managing this financial responsibilit y. We believe that both an indeterminate or an exceedingly lo ng post

- inject io n site

- care peri o d will discourage the development of private sector products to address financial responsibilit y and discourage sequestration in general.

Given the limited ri sk profile of th e post

- operational phase of geol ogi c storage, th e precedent set by other proposal s, and the likely impediments to financial responsibilit y and insurance caused by an uncertain or exceedingly lengthy post

- inject io n si te care peri od, we think that a 50

- year post

- injection site care period is unsupported by th e science, unnecessary to pro tect USDWs and unwarranted by current EOR experience. While we agree that in most instances site

- specific performance standards are most appropriate, we believe that in this instance a definite and reasonable timeframe should be established that is suppor ted by the relat ive r isks invo lved and that facilitates the development of financial assurance products. We believe a 10 year post

- injection site care peri od protects USDWs, facilitates post

- inject io n financial assurance and is consistent with our underst anding of how geologic trapping of CO 2 occurs.

III. A NY F INAL R ULE M UST C LEARLY A DDRESS P OTENTIAL E XPOSURE UNDER RCRA

AND CERCLA

EPA can and sho ul d simul taneously protect underground sources of drinking water and promote the capture of carbon dioxide. Its strategy in both areas should be crafted to avoid unintended consequences. EPA’s goal in this rulemaking should be to fulfill it s obligat io ns to protect the nat io n’s USDWs from both naturally

- occurring and

man

- made contaminants, while at the same t ime promoting progress towards successful commercial

- scale carbon capture and storage in order to address broader environmental protecti on concerns.

If EPA is going to address these broader concerns by establishing a framework for th e inject io n and sequestration of CO 2 in addit io n to the incidental storage that occurs in EOR activit ie s, it must address potentially limit less liabilit y u nder other sta tu tes that EPA administers, including CERCLA 40 and RCRA 41 . Liabilit y u nder these statutes would act as a strong deterrent to the development of CCS.

Regulated industry has learned a great deal in the last 30 years regarding environmental liabilit y. Whe n Congress passed CERCLA, it imposed jo int and several liabilit y o n landowners, transporters, and generators of hazardous substances and it made th at liabilit y r etroactive. Most recently, the Supreme Court, in Massachusetts v. EPA, 549 U.S. 497 (2007), re cogni zed that the Clean Air Act (“CAA”), with its “capacious” definit io n o f a ir pollutant, could be used to regulate substances (in this case, CO 2 ) which

40 Comprehensive Environmental Response, Compensation, and Li ability Act (“CERCLA”), 42 U.S.C. §§ 9601

- 9675.

41 Resource Conservation and Recover y Act (“RCRA”), 42 U.S.C. § 6901

- 6992k.18

Congress appeared to not intend to regulate and whose regulat io n under many provisio ns of th e CAA (i.e ., the NAAQS) is awkward at best. One lesson fro m t hese statutes and the Courts’ interpretation is that regulated industry cannot underest imate its potential liabilit y fo r pollution, irrespective o f it s com pliance wit h current regulat io ns and irrespect ive of th e magnitude of its role in the waste disposal process.

Accordingly , as EPA attem pts to prom ote efforts to reduce anthropogenic CO 2 emissio ns, it faces an ever more cautious regulated communit y. We urge EPA to take determined steps to provide regula tory clari ty as to com

pliance obligat io ns and potential fo r liabilit y.

A. EPA Should Ensure Clarity Regarding the Possible Coverage of CCS under RCRA

Re garding RCRA, in Section 2.I of the proposal, EPA considers whether the CO 2 stream is a hazardous waste. It notes that the composit io n of a particular CO 2 stream will depend on the source of CO 2 , the flue gas scrubbing techno lo gy , addi tives, and the CO 2
c apture techno lo gy . EPA concludes that it cannot make a “categorical determinat io n” as to whether injected CO 2 is hazardous under RCRA. Such a determination must be made by owners and operators, however, and a posit ive finding would mean that the well

wou ld be subject to UIC Class I requirements. Thus, EPA’s failure to resolve this issue coul d inhibit permitt ing of wells under the proposed new Class VI regime.

The Proposed Rule asserts that its design changes are meant to address the

mo bilit y a nd cor rosivit y caused by lo ng term geologic sequestration of CO 2 , and not the lo ng term storage of hazardous wastes. EPA seeks comment on its definit io n of “carbon di oxide stream ” to exclude hazardous wastes:

“Carbon dio xide stream means carbon dio xide that has been captured from an emissio n source (e.g., a power plant), plus incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the inject io n process. This subpar t does not apply to any carbon dioxide stream that meets the definitio n of a hazardous waste under 40 CFR part 261.”

Using its authorit y u nder RCRA, EPA has previously excluded certain substances fro m co verage under 40 C.F.R. § 261.2. CO 2 is no t exclude d under this sect io n, but it is also not specifically included as a hazardous substance under 40 C.F.R. § 261.3. Thus, th e status of CO 2 under RCRA remains a concern.

A determinat io n t hat CCS activit ies are subject to RCRA would subject those activit ies to stringent handling, storage, and disposal procedures above what would be requi red by the Proposed Rule (except with regard to the post

- clo sure peri od f or financial responsibilit y, which, at 30 years, would be less demanding than the proposed 50 year19

te rm fo r a Class VI well). Such a finding would serve to inhibit the development and adopti on of CCS, to the frustration of EPA’s larger efforts to reduce CO 2 emissio ns.

Denbury sets out this basic informat io n only to i nt roduce i

ts specific responses to EPA’s statements and request for comment in the proposed rule. RCRA defines so lid waste to include “discarded material, including so lid, liquid, semi

- so lid, or contained gaseous material result ing fro m industrial . . . operations.” 42 U.S.C. § 6903(27). EPA shoul d clarify that injected CO 2 in t he form of a supercritical fluid does not fall wit hin the definit io n o f a solid waste because it is neit her a liquid nor a contained gaseous material. Moreover, any CO 2 supply th at i s acquired for value for use i n EOR or EGR activit ies shoul d be explic it ly excluded as it would not be “discarded” at all, but sold for valuable consideration. Were CO 2 to not be a solid waste, it would not be subject to RCRA’s waste determinat io n provisio ns. Only in those cases wher e the CO 2 stream is in the form of a liquid (which it would not be, at pipeline or reservo ir condi ti ons) woul d it be subject to these provisions.

Using authority granted by RCRA § 3001, EPA has exempted fro m RCRA’s definit io n o f so lid waste certain low

- toxi ci ty wastes that exist in high

- vo lu mes, including dom esti c sewage, mining wastes, and certain nuclear materials, when those materials are covered by other laws. Similarly, EPA should consider its comprehensive regulat io n of CCS under the UIC permitt i ng provisio ns to be a sufficient reason to exempt injected supercri ti cal CO 2 from RCRA’s coverage as a so lid waste even where it cannot be sold and used for EOR operations.

Even if EPA decides not to exclude or exempt injected supercrit ical CO 2 from th e definit io n o f so lid waste, EPA could and should exempt injected CO 2 from the definit io n of hazardous waste. A hazardous waste under RCRA is a so lid waste that, because of its “quant it y, concentration, or physical, chemical, or infect io us characterist ic s ” may pose a substant ia l present or potential hazard to human health or the environment. 42 U.S.C. § 6903(5). Hazardous wastes can be specifically listed by EPA, have hazardous characterist ic s (such as corrosivit y, react ivit y, etc), be mixed wit h a liste d waste, or be derived fro m a listed waste. In the proposed rule, EPA raises the spectre that the inject io n of CO 2 in conjunct io n with hazardous components could cause it to be considered a hazardous waste. Because CO 2 storage will be closely regulated u nder the proposed rule, EPA should exempt stored CO 2 from the definit io n of hazardous waste, as it has done for wastes associated with the exploration, development, and production of crude oil, natural gas, and geothermal energy. See Regulatory Determinat ion for Oil and Gas and Geothermal Exploration, Development, and Production Wastes , 53 Fed. Reg. 25,446 (July 6, 1988).

Even if at present EPA does not foresee bringing an enforcement action for CCS activit ies, it is important for EPA to exempt CCS act ivit ies fro m RCRA’s definit io n of solid and hazardous waste to foreclose the availabilit y o f a cit izen suit under section 7002, brough

t, perhaps by ant i

- CCS act ivists, and the maintenance of which would irreversibly chill CCS projects.20

B. EPA Should Exclu de Injection and Geologic Storage of CO 2 from Coverage Under CERCLA

Regarding CERCLA liabilit y, in sect io n II.J of the preamble to the Proposed Rul e, EPA notes that the CO 2 st ream may contain hazardous substances or that the CO 2 stream coul d react with groundwater to produce hazardous substances, and concludes that “w hether or not there is a ‘hazardous substance’ that may result in CERCLA liabilit y f rom a sequestration facilit y depends ent ir ely on the m ake

- up of the specific CO 2 stream and of the environmental media (e.g., soil, groundwater) in which it is stored.” 73 Fed. Reg. at 43,504. EPA notes that CERCLA exempts fro m lia bilit y c ertain “federal ly permitted releases,” including releases in co mp liance with a UIC permit under SDWA, and recognizes that Class VI permits will need to be structured to not permit “inappropriate hazardous releases.” Id . EPA also requests comment on “particular si tuati o ns” where there exists the potential for “releases fro m t he well which are outside th e scope of the Class VI permit.” EPA requests comment on “other considerat io ns associ ated wi

th th e presence of impurit ies in the CO 2 stream rel ated to CERCLA.”

Denbury is concerned that any potenti al for CERCLA liabilit y w ill deter efforts to develop CCS projects. Under CERCLA, private parties or government entit ie s can sue to recover “response costs” associated with any “release” fro m a “facilit y” of a “hazardous subst ance.” Liabilit y is retroactive, jo int and several, and falls upon both current and past owners of facilit ies, and on those who generated or transported those “hazardous substances.” 42 U.S.C. § 9607(a). The broad nature of CERCLA liabilit y makes it a

v igorous means of addressing sites contaminated with hazardous substances, but when applied to CCS would serve to discourage regulated parties who would otherwise undertake carbon sequestration.

Pure CO 2 is no n

- toxi c at l ow concentrati ons and is not a l isted hazardous waste under environmental statutes that CERCLA cross

- references in defining “hazardous substances.” While it is certainly the case that CO 2 is not the type of “hazardous substance” that Congress envisio ned when it enacted CERCLA, the defin it io n t hat Congress included in the statute is reminiscent of the “capacious” definit io n of “air pollutant” that the Supreme Court gave effect to in Massachusetts v. EPA, 549 U.S. 497 (2007), to apply provisi ons of th e Cl ean Air Act to CO 2 , something that Co ngress showed no intent to do when it enacted the Clean Air Act. To avoid a similar outcome here, the EPA should define that the inject io n of CO 2 under a Class VI permit const it utes a “federally permi

tted rel ease.”

EPA’s definit io n o f “federally per mit ted rel ease” includes “any inject io n of fluids authori zed under Federal underground inject io n control programs or State programs submitted for Federal approval . . . pursuant to part C of the Safe Drinking Water Act . . .” 42 U.S.C. § 9601(10). CERCLA exempts a federally permitted release fro m r esponse cost recovery act io ns. 42 U.S.C. § 9607(j) (“Recovery by any person (including the United States or any State or Indian tribe) for response costs or damages result ing fro m a federally permi

tted rel ease shall be pursuant to existing law in lieu of this sect io n.”) In th e past, EPA has made only minimal efforts to clarify the scope of the federally21

permitted release exemption (the “FPR exempt io n”). In 1988, it stated in the preamble to a proposed rule tha t w oul d have clarified the FPR exempt io n t hat “any underground inject io n of hazardous substances permitted under a State program . . . or EPA

administered program, is considered federally permitted for purposes of CERCLA notification.” Reporting Exemption s for Federally Permitted Releases of Hazardous Substances; Proposed Rule , 53 Fed. Reg. 27,268, 27,273 (Jul. 19, 1988). EPA did not finalize that proposal. EPA should use the present proposed rulemaking to reaffirm that an authorized release under the UI C program qualifies for the exempt io n fro m CERCLA cl eanup liabilit y u nder sect io n 9607.

To be sure, this would be a narrow exempt io n, because EPA has also taken the posi ti on that the FPR exempt io n does not apply to accidental releases. See Guidance on the CERCLA Section 101(10)(H) Federally Permitted Release Definition for Certain Air Emissions , 67 Fed. Reg. 18,899, 18,903 (Apr. 17, 2002). In U.S. v. United Nuclear Corp ., EPA took the posi ti on that seepage from uranium tailings ponds into groundwater was not part of the permitted activit y. 814 F. Supp. 1552 (D.N.M. 1992). In Idaho v. Bunker Hill , the court accepted a state’s claim that CERCLA liabilit y will attach to rel eases “which were not expressly permitted in the various permits, which exceeded th e limitations established by the permits, or which occurred during a time period when there were no permits.” 635 F. Supp. 665, 673

- 74 (D. Idaho 1986). Accordingly, EPA could recogni ze the applicabilit y of the FPR exempt io n without significant ly revisi ng its posi ti on on the FPR.

Yet another basis on which to exclude injected supercritical CO 2 fro m CERCLA’s ambit is the fact that CO 2 is current ly a co mmo di ty

- whether used in the food and beverage industry or for EOR

- and will likely remain so for ye ars to come. Denbury currently has contracts to purchase anthropogenic CO 2 fro m mu lt iple sources. While the pri ce of the CO 2 varies, it has a significant value to Denbury and other EOR operators. As di scussed above, the most realist ic path for storage of CO 2 over the next several years is incidentally in o il a nd gas bearing formations. Thus, captured anthropogenic CO 2 will be a commodit y fo r purposes of EOR for many years. 42 Further, Denbury or other EOR operators may need to access the stored CO 2 fo r use in future EOR operations or for other unforeseen purposes where the use of supercrit ic al substances is necessary and desirable. The proposed rule should thus recognize these factors and clearly classify CO 2 as a commodit y t hat is excluded fro m CERCLA ’s coverage.

To be sure, EPA does not have the authority to protect CCS operations fro m liabilit y u nder state statutes and commo n law, and Denbury is not suggesting that EPA
attem pt to do so in the context of this rulemaking. However, Denbury is askin g EPA to use its authority under laws it administers, to reduce the overall risk of exposure for

com panies engaging in CCS under a UIC permit regime.

42 See also Fer guson, et al., supra text accompanying note 34, (estimating potential market for CO2 for EOR purposes around 7,500 million metric tonnes between now and 2030).22 IV. S UGGESTED C HANGES TO L ANGUAGE OF P ROPOSED R ULE

A. § 146.82 Required Class VI permit information

This sect io n o f t he proposed rule sets forth the informat io n which the owner or operator must submit to the Di

rector in order to obtain a Class VI well permit. All o f t he inform at io n specified must be part of the permit applicat io n. But som e data are not
necessary in light of other provisio ns of the current proposal, and so me are not attainable pri or to well drilling (applicants will not drill the well until it has been approved, otherwi se they risk drilling an unusable well). Still other data can only be obtained after inject io n act ivit ies have been init iated. Post

- drilling and post

- inject io n data should not be
requ ir ed as part of the applicat io n process but instead should be considered confirmatory data that m ay be submitted after they are obtained. In general, the proposed rule should be mo dified to requi

re submissio n o f o nly those data which are needed for consid erat io n of th e init ial permit applicat io n, and only those data that may be reasonably obtained pri or to commencement of installat io n and operation of the inject io n well.

1. EPA Proposed : §146.82 (f) Maps and stratigraphic cross sections indicating the
gen eral vertical and lateral limits of all USDWs, water wells and springs within the area of review

, their positions relative to the injection zone(s) and the direction of water movement, w

here known;

So long as the Applicant proposes to inject CO 2 below th e lo werm ost USDW, as proposed under the rule, there is no just ificat io n to requi re maps and stratigraphic cross
sect io ns fo r the ent ir e extent of those USDWs above the lowermost USDW, although mapping and stratigraphic cross sections in the immediate vicini ty of th e proposed inject io n lo cati ons (e.g. where the inject io n wells will be drilled) should st ill be required. Data regarding all USDWs in the AoR will likely be costly and/or difficult to collect and, except as noted above, the usefulness of those dat a seems quest io nable.

Accordingly , Denbury suggests that subparagraph (f) should be modified as fo llo ws:

(f) Maps and stratigraphic cross sect io ns indicat ing the general vertical and lateral limits of all the lowermost USDW s , all USDWs in the immedi ate vicinity of the proposed injection well(s), water wells and springs wit hin the area of review, their posit io ns rel at ive to the injection zone(s) and the direct io n of
water m ovement, where known;

2. EPA Proposed : §146.82(l) The results of the formati on testing program as required in paragraph (j) of this section; (r) All available logging and testing program data on the w

ell required by§ 146.87; (s) A demonstration of mechanical integrity pursuant to § 146.89;

The requirements of subparts (l), (r) an d (s) of § 146.82 cannot be met unt il a ft er the well is drilled. For example, subparagraph (l) references (j), formation testing. Clearly fo rm at io n t esting is a drilling or post complet io n operation. Similarly, logging and mechanical integrit y t esting a lso are drilling or post well co mp let io n operations. Because23

thi s informat io n will be collected post applicat io n approval, it should not be required pri or to the granting of the Class VI permit.

Denbury suggests that EPA modify § 146.82 to eliminate sub parts (l ), (r) and (s) because th ose data do not belong in and in fact may not be available as part of a permit applicat io n.

B. §146.84 Area of review and corrective action.

EPA’s pr oposed rule allows each applicant to define the Area o f Review (“AoR”) associ ated wi

th th e sequestration project. Denbury has no object io n t o thi s flexible approach as it allows the size and shape o f t he AoR to reflect the unique geo lo gy of each CO 2 seque strati on proj ect. However, under §146.84 (a), to define the AoR, an applicant must use a model capable of considering the physical and chemical properties of all phases of the injected carbon dioxide stream. Denbury is uncertain that there is a model th a t can sat is fy this requi

rement. Accordingly , Denbury suggests that the proposed rule be amended as fo llo ws:

§146.84 Area of review and corrective action

. (a) The area of review is the region surrounding the geologic sequestration project th at may be impa cted by th e injection act ivit y. The area of review is based on

com putati onal mo deling that

, to the extent practicable and to the extent determined to be necessary by the Director, accounts for the material physical and chemical properties o f all critical phases of the injected carbon dioxide
stream

.

C. § 146.86 Corrosiveness of the carbon dioxide stream, and formation fluids.

Under the proposed rule, t he Di rector is required to determine and specify casing and

cem ent ing requirements to ensure that a proposed Class VI well is constructed and

com pleted to prevent the movement of fluids into or between USDWs or into any unauthori zed zones and to permit approp ri ate testing and monitoring. The proposed rule does not adequately explain or justify the informat ion requirements set forth therein.

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

The proposed rule requires an applicant to submit to the Director informat io n on the corrosiveness of the carbon dio xide stream, and format io n fluids. Neither the proposed rul e nor the Preamble adequately explains whether the inform at io n requested is corrosiveness of the combined streams of CO 2 and format io n fluids, or each independent
stream (which seems unnecessary). Further, the proposed rule or the Preamble should el aborate on what ty

pe of data may be acceptable

– laboratory data fo r hy pothetical streams, empirical testing, analogous wells? Clarificat io n is requested on the af orem ent io ned requirements.24

2. EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells. (3) At least one long string casing, using a sufficient num ber of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages.

*

*

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

Addit io nal proposed requirements affect ing casing and cementing o f C la ss VI wells are set forth in §§ 146.86 (b)(3) and (5) as quoted above. The requirement to cement the casing to the surface is unnecessary, expensive and contrary to best practices. Under acceptable best practices, the long string casing would not be cemented to the surface so th at the pressure between the surface casing and long string can be monitored to determine if there is migrat io n between the long

- string casing and the surface casing. The cementing requirement proposed above would limit the abilit y t o m oni tor f or migration o f injected fluids, in this case CO 2 , behind the casing. Addit io nally , Denbury’s field data indicat es that the proposed casing and cement ing requirements are costly while provi ding limit ed, if any benefit. According to our findings, under exist ing Class II UIC rul es, a convent io nal cement ing program costs approximately $20,000 per well. Under th e cem e nt ing program proposed for Class VI wells the cost could escalate to approximately $193,000 per well

— a potenti al $173,000 increase, represent ing a 10% increase in total per well costs. 43

Denbury suggests an alternat ive that protects USDWs, but at a reaso nable cost. Rather th an require cement ing of the long string casing to the surface, the proposed rule should requi re cement and cement addit ives to be compatible with the carbon dioxide stream and fo rm at io n fluids that cover the injection zone and the con fining zone, and then require standard (API, ASTM International, or comparable standards) industry cements to a certain distance above the confining zone. This would place cements that may require special addit ives at the point where USDWs are most effect ively protected from th e mixture of carbon dio xide and format io n fluids that could produce carbonic acid.

Denbury suggests the following revisio n:

§146.86 (b) Casing and Cement ing of Class VI Wells. (3) At l east one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface injection zone and confining zone and an authorized distance above the confining zone,

43 For a ty pical well completed under Class II UIC rules, the total costs equals $1,700,000.25 submitted by the permittee and approved by the Direc tor in one or more stages

. *

*

* (5 ) To protect USDWs
, C cem ent and cement additives must be com patible wit h th e carbon dioxide stream and format io n fluids and of sufficient qualit y a nd quant it y t o m aintain integrit y o ver the desi gn operating life o f t he w ell geol ogi c sequestration project must be used across the injection zone and confining

zone . The integrit y and lo cat io n of the cement shall be verified using techno lo gy capable of evaluat ing cement qualit y r adially and ident ifying the locat io n of channels to ensure that USDWs are not endangered.

D. § 146.87 Logging, sampling, and testing prior to injection well operation.

EPA’s proposed § 146.87 delineates t he informat io n a permittee must collect during the drilling and construction of a Class VI well, prior to actual inject io n act ivit ies

. Alt hough th e proposed rule generally allows the Director to approve alternative methods that provi de equivalent or bette r information, it is not clear that the Director can utilize that regul atory flexibilit y to waive unnecessary, duplicative testing which the proposed rule requi res in several subparagraphs.

1. EPA Proposed § 146.87 (a)(2) Before and upon installation o f the surface casing:... (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented

. The requirements in §146.87(a)(2)(ii) to secure and submit specified logs before, upon and after surface casing installat io n is excessive. The proposed rule fails to provide a sufficient justificat io n fo r requiring a cement bond and variable densit y lo g bef ore and
upon installat io n of the long string casing, and requiring a temperature log aft er th e casing is set and cemented. T emp erature l ogs are seldom used in the drilling industry to determine cement characteristics as they do not provide useful data regarding the bonding of cement. The rules should be modified to allow the permittee to select between the specified logs and a ny other logging tool approved by the Director as follows:

§146.87(a)(2)(ii) A cement bond and vari able densi ty lo g or other approved tool
, and or a tem

perature l og after the casing is set and cemented. [see § 146.12(d)(2)(i)(B) Criteria and Standards ap plicable to Class I nonhazardous wells: Construction Requirements .]

*

*

* (5) Any alternat ive methods that provide equivalent or better informat io n and that are required of and/or approved of by the Director. The Director may waive any log or test specifi ed in this subparagraph.26

2. EPA Proposed §146.87 (a)( (3) Before and upon installation of the long string casing: (i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any other logs the Director requires for t he given geology before the casing is installed; and

Once again, the proposed rule requires test ing that would be o f lit tle benefit in protecting USDWs, but would impose significant costs on operators. For example, Denbury sees no basis to run a fracture finder log in every well. Fracture finder logs will only see minor fractures within the individual format io ns. The log does not provide informat io n o n whether these minor fractures can act as conduits between the inject io n zone and confining zone. To av oi d unnecessary data collecti on and submittal , the rul es shoul d allow the applicant to propose and just ify a logging suite based on the reservoir and geol ogy associ ated wi

th th e parti cular CO 2 project. The Di rector of course should be allowed to approve, or recommend revisio ns to the proposed suite. This would avoid mandat ing unneeded testing. Denbury suggests the following revised rule, incorporating thi s proposed change:

§146.87 (a)( (3) Before and upon installat io n of the long string casing: (i ) Re sist ivit y, spontaneous potential, porosit y, caliper, gamma ray, fracture finder lo gs, and any other or any suite of logs submitted by the permittee and approved by lo gs th e Director before the casing is installed requi res for considering th e given geo lo g y bef ore the casing is installed ; and

*

*

*

The proposed rule also requires unnecessary and duplicat ive logging wit h respect to the lo ng

- string casing.

3. EPA Proposed §146.87 (a)( (3) Before and upon installation of the long string casing : (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented.

Denbury suggests that the logging options it recommends wit h respect to surface casing also apply for the lo ng

- string casing. Thus, the proposed rule should be re vised as fo llo ws:

§146.87(a)(3)(ii) A cement bond and vari able densi ty lo g or other approved tool
, and or a tem

perature l og after the casing is set and cemented. [see § 146.12(d)(2)(ii)(C) Cr iteria and Standards applicable to Class I nonhazardous wells: C onstruction Requirements .]

4. EPA Proposed §146.87 (b) The ow ner or operator must take and submit to the Director whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept cores from nearby w

ells if the ow

ner or operator can demonstrate that core retrieval is not27

possible and that such cores are representative of conditions at the w ell. The Director may require the ow

ner or operator to core other formations in th e borehole.

Denbury opposes the requirement to collect cores fro m mo re than one (1) well wit hin a CO 2 proj ect. As a pract ical matter, the majority of the important physical and geophysical properties of the inject io n reservoir, including the particular a ttributes of the confining format io ns can and are required to be evaluated from logs and other scient ific, reliable measures. A “who le core,” as specified in §146.87(b) is only a very small sample o f t he attributes o f a reservo ir and a sidewall core, an e ven smaller sample. The fo rm er is very expensive to collect, and the latter often not available. Neit her is essentia l given the vast amount of data otherwise required, and mult ip le samples, as proposed by th e rule, are not reasonable. The unreasonablene ss of th e who le core, sidewall core and
extra core sam

pling is evident upon consideratio n o f t he sheer vo lu me o f p hysical evidence that this provisio n al on e may produce. For example, in Texas there are over 5000 exist ing Class II CO 2 inject io n wells. If a small fract io n o f t hese wells are converted to Class VI CO 2 injection wells fo llowing the co mp let io n o f productio n activit ies, there will be a large universe of cuttings. Where will t he regulatory agency store this magnitude o f cuttings? This may become a part icu lar problem given the total number of CO 2 sequestration projects that may be proposed.

Denbury suggests the following:

§146.87 (b) At the specific request of the Director and only where core ret rieval is possible, t T he owner or operator must t ake and submit to the Director

a whole core s or si dewall core s of th e inject io n zone and confining system and fo rm at io n fluid samples from the injection zone(s). The Director may accept cores fro m near by wells if the owner or operator can demo nstrate that co re retri eval is not possible and that such cores are representative of condit io ns at the well. The Di rector m ay requi

re the owner or operator to core other format io ns in the boreho le.

5. EPA Proposed §146.87 (d) At a minimum, the owner or operator must determine or calculate the follow ing information concerning the injection and confining zone(s): (1) Fracture pressure; (2) Other physical and chemical characteristics of the injection and confining zones; and (3) Physical and chemical characteristics of the formation fluids in the injection

zone.

Subparagraph (d) of § 146.87 provi des permi tte es wit h a generic list of data that is requi red regarding the inject io n and confining zone. Fracture pressure is specified. Under the circumstances, fracture press ure shoul d only be calculated, rather than “determined” as any determinat io n based on techniques beyo nd mathemat ical calculat io n will require coring or perforation o f t he casing, potentially decreasing the mechanical int egri ty of th e well and running direc tl y co unter to the object ive of the proposed rules.28

Wit h respect to other generic data EPA seeks regarding the injection and confining zones, th e proposed rule does not to provide sufficient guidance to the permittee on the scope of data required on the f

orm at io n fluids and reservo ir zones. Denbury requests clarificat io n and specifics both wit h respect to the nature and t ype of “physical and chemical characterist ic s” EPA expects a permittee to submit in response to the requirements of 146.87(d) (2) & (3).

6. EPA Proposed §146.87 (f ) The ow ner or operator must provide the Director with the opportunity to w

itness all logging and testing by this subpart. The ow ner or operator must submit a schedule of such activities to the Director 30 days prior to conducti ng the first test and submit any changes to the schedule 30 days prior to the next scheduled test.

The agency requires the submission o f a proposed logging and testing schedule at least 30 days in advance o f t hose proposed activit ie s. Although a logging and testing schedule certainly can be designed 30 or more day s in advance, the actual date that logging is perform ed is usually available only 24 to 48 hours in advance o f actual logging operati ons. A mandatory 30 day notice is simply not practical for lo gging and testing.

Denbury asks that notice requirements in this subpart be adjusted to take into account the practi cal limitat io ns experienced routinely in field operations. Suggested revised language is set forth below.

§146.87 (f) The owner or operato r m ust provi de the Director with the opportunit y to witness all logging and testing by this subpart. The owner or operator must submit a proposed schedule of such act ivit ies to the Director at least 30 days pri or to conducting the first test and submit not ice at least 24 hours in advance of the conduct of any actual logging and testing. an y c hanges to the schedule 30 day s pri or to the next scheduled test

.

E. § 146.88 Injection well operating requirements.

1. EPA Proposed §146.88 (c) The ow ner or operator must fill the annulus betw een the tubing and the long string casing w ith a non

- corrosive fluid approved by the Director. The ow

ner or operator must maintain on the annulus a pressure t hat exceeds the operating injection pressure, unless the Director determines that such requirement might harm the integrity of the w ell.

EPA’s suggested Mechanical Integrity (“MI”) rule to maintain pressure on the annulus exceeding the operating inject io n pressure will, in most cases, result in an exceedance o f th e burst pressure of the casing. If the operator is required to maintain pressure on the annulus at a rate that i s greater than the inject io n pressure (as indicated in EPA proposed §146.88 (c)), m oni

toring the annulus pressure may not be an accurate indicator of mechanical integrit y. Th e EPA appears to recognize this likelihood and thus allows the Di rector to waive the requi rement. However, the rul e shoul d not requi re a quest io nable practi ce and th en permit its waiver. Rather, the practice should only be required if the29

Di rector m akes a determinat io n t hat the conduct of the test will NOT cause a problem. The suggested revisio n is encapsulated below:

(c) The owner or operator must fill the annul us between the tubing and the long string casing with a non

- corrosive fluid approved by the Director. If the Director determines that such requirement will not harm the integrity of the well, T t he owner or operator must maintain a positive pressure on the annulus a pressure th at exceeds the operating inject io n pressure. ., unless th e Di rector determines that such requirement might harm the integrit y o f t he well

.

2. EPA Proposed §146.88 (e) The ow ner or operator must install and use continuous recording de vices to monitor: The injection pressure; the rate, volume, and temperature of the carbon dioxide stream; and the pressure on the annulus betw een the tubing and the long string casing and annulus fluid volume; and must install and use alarms and automatic dow n

- hole shut

- off systems, designed to alert the operator and shut

- in the w

ell when operating parameters such as annulus pressure, injection rate or other parameters approved by the Director diverge beyond permitted ranges and/or gradients specified in th e permit;

The installat io n and use of automat ic down

- ho le shut

- off systems creates a potential avenue for leakage and is unnecessary on land

- based onshore sy stems. Down

- hole shut

off systems, more commo nly used in o ff

- shore operati ons, serve to shut in t he well and prevent reservo ir fluids fro m e xit ing the wellbore. They are used in off

- shore operati ons because of the risk of damage to the wellhead from at mo spheri c or anthropogeni c pheno me non, such as a hurricane causing extensive plat fo rm damage or a sh ip colliding wi th a platform . But in an onshore inject io n system, a down

- ho le shut

- off system will not determine or deter leakage of fluids in the wellbore and therefore is not effect ive in protecting USDWs. Also, the likelihood of damage to an onshore w ellhead is extremely

rem ote . The greater risk in a Class VI onshore operation is that the mechanics o f t he down

- ho le shut

- off system will be co mpromised or malfunction. Such a malfunct io n woul d requi

re rem ov al of the tubing and shut

- off system equi pment, th ereby creating a potenti al unwanted migration path. The use of automat ic down

- ho le shut

- off systems shoul d be limited to off

- shore operati ons.

Furtherm ore, the requi

rement to continuously mo nit or the annul us fluid vo lu me is impract ical, because it d oes not provi de any m eaningful data regarding potenti al probl ems wit h the operati on of th e well . Requiring the cont inuous mo nit oring o f t he

am ount of annulus fluid added during operations is more practical and will reveal potenti al leakage paths. Denbury reco mmends the fo llo wing:

§146.88 (e) The owner or operator must install and use continuous recording devices to monitor: The inject io n pressure; the rate, volume, and temperature of th e carbon dioxide stream; and the pressure on the annulus between the t ubing and the long string casing and the volume of annulus flu id added to the annulus

vo lu me ; and the owner or operator mu st install and use alarms and autom at ic down

- ho le shut

- off systems, designed to alert the operator and shut

- in off the well30 when opera ting parameters such as annulus pressure, inject io n rate or other
param eters approved by th e Di rector diverge bey on d permitted ranges and/or gradi ents specified in the permit. If the operation involves off

- shore injection, the owner or operator must insta ll and use alarms and automatic down

- hole shut

- off systems, designed to alert the operator and shut

- in the well if the wellhead is damaged or when operating parameters such as annulus pressure, injection rate or other parameters approved by the Director di verge beyond permitted ranges and/or gradients specified in the permit ;

(f) If a n down

- ho le autom atic shutdown is triggered or a loss of mechanical int egri ty is discovered, the owner of operator must immediately invest igate and ident ify as expedit io usly as possible the cause of the shutoff.

*

*

*

F. § 146.89 Mechanical integrity.

1. EPA Proposed §146.89 (c) At least once per year, the ow ner or operator must use one of the follow ing methods to determ ine the absence of significant fluid movement under paragraph (a)(2) of this section: (3) A casing inspection log, if required by the Director.

Amo ng the test protocols prescribed by the proposed rule to confirm lack of significant flui d mo vement is a ca sing inspect io n lo g. Al th ough this log is optional, it may be requi red by the Director. Conducting a casing inspection log will require the tubing to be pulled fro m a well, and that in turn substant ia lly increases the possibilit y o f a well control
event (that is a loss of control over well operation). Accordingly, the technique should only be mandated when other testing methodologies are unavailable. Denbury suggests th e fo llo wing edi

t:

§146.89 (c) At least once per year, the owner or operator must use one of the fo llo wing methods to determine the absence of significant fluid movement under paragraph (a)(2) of this sect io n: (3) A casing inspect io n lo g, if a tracer survey or a temperature or noise log cannot be obtained and a casing inspection log is thus required by the Director.

G. § 146.90 Testing and monitoring requirements.

1. EPA Proposed §146.90(b) Installation and use, except during w ell workovers as defined in § 146.86(d), of continuous recording devices to monitor injection pressure, rate and volume; the pressure on the annulus between the tubing and the long string casing; and the annulus fluid volume;

Consistent with our comment regarding proposed § 146.88(e) in Section 5 a bove, Denbury is unaware of a methodology to monitor the actual volume o f annular fluid in31

th e annulus on a continuous basis, and thus seeks agency clarification on this portion of th e proposed rule.

2. EPA Proposed §146.90 (c) Corrosion monitoring of t he well materials for loss of mass, thickness, cracking, pitting and other signs of corrosion must be performed on a quarterly basis to ensure that the w ell components meet the minimum standards for material strength and performance set forth in § 146.86(b ) by: (1) Placing coupons of the w ell construction materials in contact w ith the carbon dioxide stream; or (2) Routing the carbon dioxide stream through a loop constructed w ith the material used in the well; or (3) Using an alternative method approved by t he Director;

Denbury believes the requirements in EPA proposed §146.90(c) related to corrosion

mo nit oring are inapplicable. In the vast majorit y o f c ases, the CO 2 will be transported to th e inject io n site through pipelines, will be dehydrated prior to tr ansportation and th erefore when injected it will be non

- corrosive. 44 In those instances, the test methods described in § 146.90(c)(1) and (c)(2) (except of course alternat ives approved by the Di rector) will not provide meaningful informat io n regarding the mechanical integrit y o f down

- ho le casing, tubing and other equipment because the CO 2 will simply not be corrosive at the surface. Consequently, to have any relevance such requirements should be reserved for situations where water saturated CO 2 is being in jected.

§146.90 (c) Corrosion mo nit oring of the well materials for loss of mass, thickness, cracking, pitting and other signs of corrosion must be performed on a quarterly basis to ensure that th e well co mponents that contact water saturated carbon dioxide streams meet the minimum standards for material strength and perform ance set forth in § 146.86(b) by: (1) Pl acing coupons of the well construction materials in contact with the carbon di oxide stream; or (2) Routing the carbon dioxide stream through a loop constructed with the materi al used in the well; or (3) Using an alternat ive method approved by the Director. The requirements of this subpart are waived when the carbon dioxide stream is dehydrated to meet pipeline specifications.

44 For evidence on CO 2 corrosiveness in the absence of free water see Don Duttlinger, “Enhanced Recover y Intertwines Nat urally With CO 2 Sequestration,” Tech Connections Column, American Oil and Gas Reporter (January 2004), available at http://www.pttc.org/aogr_columns_archived/aogrcojan04.htm (From the processing/injection standpoint, CO 2 is no ncorrosive as long as it is dr y. Pr oving that point, Kinder Morgan has hy

dro

- tested the 32

- year

- old CRC Pipeline built in 1971 to transport CO 2 . Only one minor failure occurred. After testing, the line was rated for 2,025 psi maximum operating pressure, which established a 200 psi inc

rease over most recent ratings); see also J. Layne, “Results of the Hydrotest of the 30

- year old Canyon Reef Carriers CO 2 Pipeline,” 2003 CO 2 Flooding Conference, University of Texas of the Permian Basin's Center for Energy and Economic Diversification, Mi dland,Texas (December 11

- 12, 2003).32

3. EPA Proposed §146. 90 (f ) A pressure fall

- off test at least once every five years unless more frequent testing is required by the Director based on site specific information;

The scope of this proposed requirement is not clear. Does the EPA proposal require the submittal of th e actual data, or m erely an analysis of the pressure fall

- of f t est?

4. EPA Proposed §146.90 (i) Any additional monitoring, as required by the Director, necessary to support, upgrade, and improve computational modeling of the area of review evaluation r equired under § 146.84(b) and to determine compliance w ith standards under 40 CFR 144.12

This sect io n effect ively proposes a “catch all” to allow the Director undefined discret io n to order unlimited and unspecified addit io nal monitoring to improve modelin g and ensure

com pliance. Vesting the Director with such addit ional undefined discret io nary authori ty increases the regulatory ri sks of the Class VI permitt ing process and accordingly increases costs. In the event that experience implement ing the proposed rul e requi res some future revisio ns to include addit io nal mo nit ori ng requirements, such changes should be proposed and adopted through appropriate rulemaking procedures and based on an adequate factual and scient ific record. However, adopting an open

- end ed power to requi re “any” addit io nal monitoring, at this early stage, undermines the purpose of provi ding a defined set of rules that members of the public may evaluate prior to making th e large investments that will be invo lved in Class VI projects. Such uncertaint y can only tend to increase costs, creating a barrier to capital formation and discouraging geol ogi c sequestrati on. Accordingly, Denbury recommends delet ing this sect io n.

H. § 146.92 Injection well plugging.

1. EPA Proposed §146.92 (b) Well Plugging Plan. (5) The type and grade and quantity of material to be used in plugging. The material must be compatible w ith the carbon dioxide stream;

The proposed regulat io n requires the wellbore to be flushed prior to plugging and thus it is unnecessary to use cement “compat ible wit h t he carbon dioxide stream.” In the absence of water, CO 2 is non

- corrosive and compatible with convent io nal cements (see di scussio n under Comment #G). Accordingly, t he rule should be revised as fo llo ws:

§146.92 (b) Well Plugging Plan. (5) The ty pe and grade and quant it y o f mat erial to be used in plugging. The material must be compatible with the carbon dioxide stream;

I. § 146.93 Post

- injection site care and site c losure.

The proposed rule establishes a 50 year default period for post

- inject io n site care. There is, however, no factual or scient ific basis for such an extensive period. Under EPA’s Resource Conservat io n and Recovery Act rules, which regulate the disposal o f ha zardous33

wastes, post closure care is limited to 30 years. 45 Default ing to an excessively lo ng peri od will increase costs and introduce greater regulatory uncertaint y, whi ch will di scourage capital format io n around CO 2 sequestration. A more prudent regulatory approach is to set a minimum period for site care, ten years, with allo wance for the Di rector to extend the period if facts and circumstances warrant a longer post

- in jecti on si te care period.

Addit io nally , the proposed rule’s 50 y ear def aul t p os t inject io n site care period, is an illusory deadline, as it is not self

- execut ing. Under the rules, post inject io n site care must continue indefinitely unt il the Director a uthorizes closure. The closure approval process coul d take years, even decades, as the Director has no regulatory incent ive to act on any post inject io n site care report. Meanwhile, a permittee may be required to continue
unnecessary and expensive mo nit o ring and reporting indefinitely.

Denbury suggests that the post

- inject io n site care rules be reconfigured to require a more limited mandatory post

- inject io n site care timeframe, and to allow for closure at the end of th at peri od unl ess the Director affi rm at ively acts to extend the post

- inject io n site care peri od. These changes are contained in the suggested text below:

§ 146.93 Post

- injection site care and site closure. (a) The owner or operator of a Class VI well must prepare, maintain, and co mp ly wi t h a plan for post

- injection site care and site closure that meets the requirements of paragraph (a)(2) of this sect io n and is acceptable to the Director. (1) The owner or operator must submit the post

- injection site care and site cl osure pl an as a part of th e permit application to be approved by the Director. (2) The post

- inject io n site care and site closure plan must include the fo llo wing informat io n:

(i ) The pressure different ia l between pre

- inject io n and predicted post

- inject io n pressures in the inject io n zone; (i i) The predicted position o f t he carbon dioxide plume and associ ated pressure front at site closure as demonstrated in the area of review evaluat io n required under § 146.84(b); (i ii) A descript io n of post

- inject io n mo nit oring location, methods,

a nd proposed frequency; and (i v) A proposed schedule for submitt ing post

- injection site care

mo nit oring results to the Director. (3) Upon cessat io n of inject io n, owners or operators of Class VI wells must ei th er submit an amended post

- inject io n site care an d si te cl osure pl an or dem onstrate to the Di

rector through monitoring data and modeling results that no

am endment to the pl an is needed. (4) The owner or operator may mo dify and resubmit the post

- inject io n site care and site closure plan for the Director’s approval within 30 days of such change.

45 40 C.F.R. § 264.117(a)(1)34 (b) The owner or operator shall mo nit or the si te f oll owing the cessat io n of inject io n to show the posit io n of the carbon dioxide plume and pressure front and dem onstrate that USDWs are not being endangered. (1) The owner or operator shall cont inue to conduct monitoring as specified in the Director

- approved post

- inject io n site care and site closure plan for at l east 50 10 years fo llo wing the cessation o f injection. At th e Upon a determination by the Director ’s that the geologic sequestration project may pose an endangerment to USDWs discretion

, the Director, at his discretion, may require th e mo nit ori ng will to cont inue for a time period specified by the Director unt il th e geo lo gi c sequestration project no longer p oses an endangerment to USDWs

. (2) If the owner or operator can demonstrate to the satisfaction o f t he Di rector before 50 10 ye ars, based on monitoring and other site

- specific data, that th e geol ogi c sequestration project no longer poses an endangerment to USDWs, th e Di rector m ay approve an amendment to the post inject io n site care and site cl osure pl an to reduce the frequency o f mo nit ori ng or m ay authori ze site closure before the end of the 50

- 10 ye ar peri od. (3) Prior to authorization for the expiratio n of the 10 year post

- injection site care period, si

te cl osure , the owner or operator must submit to the Director a dem onstrati on, based on monitoring and other site specific data, that the carbon di oxide pl ume and pressure front have stabilized and that n o addi ti onal

mo nit oring is needed to assure that the geologic sequestration project does not pose an endangerment to USDWs. (4) If within 180 days after the submittal of the data required under subparagraph (3) above the Director determines that the geolog ical sequestration project may continue to pose an endangerment to USDWs, he shall so notify the owner or operator of his determination and the basis therefore, and If such a demonstration cannot be made (i.e., if the carbon di oxide pl ume and pressure fro nt have not stabilized) after the 50

- year period, th e owner or operator m

ust submit to the Director a plan to continue post

- inject io n si te care. (5) If within 180 days after the submittal of the data required under subparagraph (3) above the Director fail s to determine and to notify the owner or operator that the geological sequestration project may continue to pose an endangerment to USDWs, site closure shall be deemed authorized by

ru le (c) Notice of intent for site closure. The owner or operator must no tify the Di rector at least 120 day s before site cl osure. At thi s time, if any changes have been made to the original post

- inject io n si te care and site closure plan, the owner or operator must also provide the revised pl an. At the di screti on of the Director , a shorter notice period may be allowed. (d) After the Director has authorized site closure or site closure is authorized by

ru le , the owner or operator must plug all mo nit oring wells in a manner which will not allow mo vement of inject io n or formation flu ids that endangers a USDW. (e) Once the Director has authorized site closure, or site closure is authorized by

ru le , the owner or operator must submit a site closure report within 90 days that35 must thereafter be retained at a location designated by the Dir ector. The report must include: (1) Documentation of appropriate inject io n and mo nit oring well plugging as specified in § 146.92 and paragraph (c) of this section. The owner or operator must provide a copy of a survey plat which has been submitted to the l ocal zoning authori ty designated by th e Di

rector. The pl at m

ust indicate the location of the inject io n well relat ive to permanent ly surveyed benchmarks. The owner or operator must also submit a copy of the plat to the Regional Administrator of the appropri ate EPA Regional Office; (2) Documentation of appropriate notificat io n and informat io n to such State, local and tribal authorit ies as have authorit y o ver drilling activit ies to enable such State and local authorit ie s to impose appropriate condit io ns on sub sequent drilling act ivit ie s that m ay penetrate the inject io n and confining zone(s); and (3) Records reflect ing the nature, composit io n and vo lu me of the carbon di oxide stream

. (f) Each owner or operator of a Class VI injection well must record a notation o n th e deed to the facilit y property or any oth er document that is normally examined during tit le search that will in perpetuit y provide any potential purchaser of the property th e fo llo wing information: (1) The fact that land has been used to sequester car bon dioxide; (2) The name of the State agency, local authorit y, and/or tribe with which th e survey plat was filed, as well as the address of the Regional Environmental Protecti on Agency Office to which it was submitted; and (3) The vo lu me of fluid injected , the inject io n zone or zones into which it was injected, and the period over which inject io n occurred. (g) The owner or operator must retain for three years fo llowing site closure, records collected during the post

- injection site care period. The owner or operator must deliver the records to the Director at the conclusion o f t he retention period, and the records must thereafter be retained at a locat io n designated by t he Di rector for that purpose.Letter ID: 0215 Commenter: Ronald Evans Organization: Denbury Re sources, Inc. (DRI)

Letter ID: 0215 Comment ID: 24271 Letter Lines: 132 to 153 ; 1623 to 1633

Comment Code: 1210 1.1.1 Comments about the proposed rule

Comment: I. INTRODUCTION -- AND A SUGGESTED COMPLEMENTARY APPROACH

The Proposed Rule is appropriately viewed as part of EPA’s broader effort to address atmospheric emissions of CO2 and other greenhouse gases ("GHG").[FN1] Analysts worldwide have identified carbon capture and storage "CCS" as one of the essential components of any successful strategy for lowering such emissions.[FN2] Within this broader context the Proposed Rule is thus intended to encourage the safe and effective development of geologic storage or sequestration of CO2 which is in additi on to existing injecti on and incidental storage of CO2 in enhanced oil or gas r ecovery operations ("EOR" or "EGR," respectively)) through Class II wells. In many respects, the Proposed Rule appears well-suited to advance that obj ective and EPA deserves credit for having developed a comprehensive approach to a complex set of issues. In other respects, however, the Proposed Rule app ears to misapprehend certain core facts relating to the physical pr operties and behavior of CO2 in some underground formations, the scale of existing CO2 st orage operations incidental to EOR operations over the last four decades, and the practical fr uits of that experience.

As a result, the Proposed Rule includes a number of requirements that long experience has shown are unnecessary for the protection of underground sources of drinking water ("USDWs") and a few th at would even prove counterproductive.

[1] See generally Regulating Greenhouse Ga s Emissions Under the Clean Air Act, Advanced Notice of Proposed Rulemaking, EPA-HQ-OAR-2008-0318, 73 Fed. Reg. 44,354, 44,397-44,440 (July 30, 2008) (discussing CO 2 emission issues under the Clean Air Act and generally soliciting public co mment on how to respond to the U.S. Supreme Court’s decision in Massac husetts v. EPA, 549 U.S. 497, 127 S. Ct. 1438 (2007) .

[2] See, e.g., Intergovernmental Pane l on Climate Change, Special Report on Carbon Dioxide Capture and Storage, 208 (B ert, Metz, et al., eds., 2005) (at 13, 45) ("IPCC Special Report on CCS") (showi ng potential contribution of CCS in reducing emissions).

Individual Response: EPA disagrees that any of the requirements in the GS rule are unnecessary. Rather, the GS regula tion tailors the UIC requirements to address the unique issues

1associated with large-scale GS, including larg e injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations.

The Agency agrees that GS is a key climate ch ange mitigation technology that is part of a portfolio of options that coul d be deployed to reduce CO2 em issions. Other options include efficiency improvements and the use of altern ative fuels and renewabl e energy sources. EPA clarifies that the purpose of the GS regulation is to ensure that GS is conducted in a manner that protects USDWs from endangerment and only applie s to owners or operato rs of wells injecting CO2 for the purpose of long-term storage.

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

Letter ID: 0215 Comment ID: 24272 Letter Lines: 154 to 164

Comment Code: 1210 1.1.1 Comments about the proposed rule 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: In addition, the Proposed Rule appears to view CO2 injection activity as a static activity in which CO2 is injected one time and never leaves the storage formation. In contrast, actual experience since 1972 reveals a far more dynamic process in which individual wells may serve as CO2 injection wells, production wells producing oil and/or CO2, or indeed multiple use wells (i.e., injection of CO2, injection of brine, brine disposal , and production). The locational value of injected CO2 is likely to vary over ti me as energy and CO2 markets evolve and it may well become valuable for a Class II EOR well to transition from Class II to Class VI and then to return to Cl ass II EOR activity. The Proposed Rules do not seem well suited to deal with such dynamic changes in the various interrelated markets for CO2, oil and natural gas.

Individual Response: EPA clarifies that the Class VI requir ements in the GS rule are for CO2 injection for long-term storage of large volumes of CO2. EPA acknowledges that multiple wells may interact at a given GS site. EPA also believe s that requiring separate permit applications for each GS well will ensure sufficient review and that the public has an opportunity to provide input on each well in the field as it is constructe d or brought online. Comments related to the economics of Class II EOR projects tr ansitioning to Class VI projects is outside the scope of this rulemaking. The purpose of this rule is to ensu re that GS is conducted in a manner that is protective of USDWs from endangerment.

EPA is developing guidance on transitioning perm its from Class II to Class VI. The guidance will assist Directors in determining whether an injection project should be transitioned from Class II, where the primary purpos e is oil and gas production, to Class VI, where the primary purpose is long-term storage of large volumes of CO2. The gu idance describes the methods available for the Director to determine changes in risk to USDWs from projects, and how the

2Director 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.

Letter ID: 0215 Comment ID: 24273 Letter Lines: 166 to 168 ; 1635 to 1642

Comment Code: 6000 3. Cost of the Proposed Rule Comment Code: 6300 3.3 Benefits of the proposed rule

Comment: We are therefore concerned that the Proposed Rule, as presently drafted, will increase the cost of geologic stor age [FN3] of CO2 without producing commensurate benefits in terms of protecting USDWs. In the case of some

[3] Relative to "sequestration," the term "storage" has become the more common usage in the worldwide community addr essing these issues. See, e.g., the European Union’s "Proposal for a Directive of the European Parliament and of the Council on the geological storage of carbon dioxide," (January 23, 2008) and the various reports and recommendations unde r the UNFCCC’s Clean Development Mechanism (available at http://cdm.unfccc.int/about/ccs/index.html) (last visited December 2, 2008). The terms "se questration" and "storage" are used interchangeably in these comments.

Individual Response: EPA disagrees that the GS rule doe s not provide comme nsurate benefits of protecting USDWs. The GS rule contains tailored requirements to ensure that wells are appropriately permitted, sited, constructed, operated, monitored, and closed in a manner that protects USDWs from endangerment. EPA acknow ledges that the Class VI requirements have associated costs beyond baseline (Class I industrial wells) cost s, and believes these costs are necessary and appropriate to address the unique challenges posed by la rge-scale GS, including large injection volumes, the rela tive buoyancy of CO2, its corrosiv ity in the presence of water, the potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations.

Letter ID: 0215 Comment ID: 24274 Letter Lines: 168 to 172

Comment Code: 1616 1.3.1.3 Fluid movement

Comment: commensurate benefits in terms of protecting USDWs. In the case of some requirements, the Proposed Rule actually tends to diminish the integrity of a storage site and thereby increase the ri sk of migration of a CO2 plume into inappropriate geologic formations. Such a result would obviously run directly counter to the Proposed Rule’s fundamental purpose and is not what EPA intends.

Individual Response: EPA disagrees that the rule requ irements would allow owners or operators to diminish the integrity of a GS site . EPA recognizes that injecting large volumes of

3CO2 for GS poses unique challenges that, if not properly managed, could endanger drinking water sources and have other adverse impacts. However, the final, tailored, Class VI requirements address the large volumes of CO2 injected, its buoyancy, potential corrosivity in the presence of water, and pot ential impurities in the CO2 stre am. In addition, EPA expects the tailored permitting, siting, construction, operation, monitoring, and post-injection site care requirements in the GS rule to prevent leakag e from injection formati ons and protect USDWs.

EPA believes that building upon th e existing UIC requirements (e.g., Class I and Class II well requirements) to develop the Class VI GS regulation provides a protective foundation for ensuring protection of USDWs that is based on su ccessful field experience and lessons learned about CO2 injection in other applications. Class I well owners or operators have experience with site characterization, well cons truction, and monitoring procedur es and technologies that are applicable to Class VI wells. Class II ER well operators have experience with managing the unique properties of CO2. To successfully fl ood a hydrocarbon field with CO2 during an ER operation, the behavior of inject ed CO2 must be well understood.

Letter ID: 0215 Comment ID: 24275 Letter Lines: 174 to 196

Comment Code: 1280 1.1.2.1 General comments on climate change/ global warming Comment Code: 6000 3. Cost of the Proposed Rule

Comment: We are also concerned that certain unn ecessary and costly re quirements in the Proposed Rule would discourage, or even foreclose, the conversion of existing Class II EOR wells to Class VI geologic sequestration wells. Th is would undercut the effectiveness of the Proposed Rule ’s provisions for such conversion. Unnecessary or unduly costly requirements would preclude CCS from playing the role that many policy analysts and govern ments worldwide believe that it must play in any successful strategy for reduci ng atmospheric concen trations of CO2. This is important because it means that the EPA may - and indeed, must - balance objectives that pull at times in competi ng directions. In other words, if the EPA’s primary objective is to reduce CO2 em issions and if CCS is an essential component of a CO2 reduction strategy, th en the rules governing CO2 injection and storage must be crafted in such a wa y as to advance the primary objective of reducing GHG emissions.

New rules for CO2 sequestration that are t oo risky or too costly for widespread use will work against this primary overa ll objective of reducing GHG emissions. Absent a broader legal foundation than th e SDWA alone, however, the EPA could conceivably find itself required to impos e conditions for sequestration that would foreclose (or unduly limit) the use of CCS as an emissions reduction tool. This, we fear, could defeat the very pu rpose of the rule in the first place. Accordingly, we suggest that EPA examine whether it may be appropriate to invoke other existing statutory authorities as part of the legal f oundation for the new sequestration rules.

Individual Response: EPA disagrees that certain requirements for the conversion of existing

4Class II EOR wells to Class VI wells are unne cessary. The final GS regulation requires at §146.81(c) that owners or operators seeking to grandfather existing Class II wells for GS demonstrate that grandfathered we lls were engineered and construc ted to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at §§146.86(b) and 146.87(a). These requirements do not impose additional stringency on conversion from Class II wells as compared to new construction. For additional information on EPA's final regulatory approach, including transitioning of EOR wells for GS, please see the final rule and preamble.

In regard to cost, the Agency clarifies that sequestration cost s are expected to be a small component of total CCS project costs. EPA esti mates that the GS rule requirements amount to approximately two percent of the total CCS projec t costs, according to the cost analysis for the final GS rule, which is in the rulemaking docket. EPA adds that promoting or incentivizing GS is outside the scope of the GS rulemaking. Rather, the purpose of the GS regulation is to ensure that GS is conducted in a manner that protects USDWs from endangerment.

EPA is developing guidance on transitioning of EOR projects. This guidance will be available on EPA’s website at http://water.epa.gov/type /groundwater/uic/wells _sequestration.cfm.

Letter ID: 0215 Comment ID: 24276 Letter Lines: 198 to 271 ; 1644 to 1704

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: Detailed comments on the Proposed Rule are provided below in Section IV of these comments, together with specific suggeste d changes to the pr oposed regulatory text that may help EPA accomplish its stat ed objectives. Before undertaking that section-by-section analysis, however, we fi rst suggest that EPA consider adding a complementary set of requirements adapted from the current Class II rules that will allow for CO2 injections and storage of CO2 at existing EOR sites to more readily transition to incremental injections and storage following completion of EOR operations. Those rules should be base d on the Class II rules that govern the approximately 45 to 50 million tons of CO2 currently being injected annually in the context of EOR operations.[FN4] Moreover, the rules should also provide for the possibility that a former EOR we ll converted to use for Class VI CO2 sequestration may return to EOR oil producti on if future circumstances make that feasible and desirable - in effect going fr om Class II to Class VI to Class II. These rules for incremental storage in existing EOR sites would complement the more extensive rules to govern CO2 injec tions and storage in saline formations or other less well-defined underground formations.

The Technical Supporting documents already expressly recognize that some oil and gas fields are likely to be good storage si te candidates and a "focus of early geologic sequestration projects":

[S]ome depleted oil and depleted gas fields also will likely be considered good candidates for sequest ration because they have proven

5traps and seals and a great deal of existing subsurface data. These types of settings have also been used extensively for methane gas injection and storage. It is antici pated that depleted oil and gas reservoirs will be a focus of early GS projects due to existing operational experience with these formations.

EPA, Technical Supporting Document: Ge ologic CO2 Sequestration Technology and Cost Analysis (June 2008) at 2 (h ereafter "EPA Technology and Cost Analysis").[FN5] The same point was ma de in EPA’s "Cost Analysis for the Proposed Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Proposed GS Rule)" (July 2008), at 1-4:

Although the majority of CO2 is likel y to be injected into saline formations over the long term, it is anticipated that, given the experience and the availa bility of background data and infrastructure related to Class II injection, early GS projects will likely be in depleted oil and gas reservoirs.

Moreover, these are the sites that are more likely to be used to receive anthropogenic CO2 from coal-to-liquids or ammonia plants, which are likely to be constructed and operational long before mate rial quantities of CO2 are captured from coal-fired electricity generating f acilities.[FN6] In addition, much of the actual research in examining the not exp ected for several years,[FN7] and EPA’s rules may well need to be modified once th e results of those extensive research projects are obtained.

Under the existing UIC rules for Class II wells, however, CO 2 injections at these sites must presumably cease once the enhanced oil or gas recovery operations come to an end (because the well would no longer fit the definition of a Class II well in the regulations).[FN8 ] The Proposed Rule could be modified to provide a transitional path for such wells to move from the incidental storage of CO2 in the context of EOR ope rations to the incremental storage of CO2 captured from industrial or power plant sources once th e oil production operations have ended. It is true that these sites w ould not be adequate to accommodate all of the CO2 that would be captured if such capture technology were deployed on all new power plants. Bu t even under EPA’s own projections in the Cost Analysis, CO2 captured from power plants is not expected to approach current injection quantities at any time during the next 25 ye ars.[FN9] Hence what is relevant here is that existi ng EOR-focused sites will be generally adequate and available to accommodat e very large quantities of those anthropogenic CO2 supplies that will actually be available for sequestration for at least the next ten years, if not for twenty or thirty years.

In effect, the Proposed Rule may be missi ng an opportunity to craft a practical transitional pathway that builds on the large scale CO2 injection and storage

6operations that are incidental to existing EOR operations to incremental storage of CO2 that could begin following termin ation of a given EOR operation. EPA should consider such a transitional path way from incidental to incremental storage at existing well-defined sites w ith existing CO2 handli ng facilities as a supplemental or complementary a pproach to the Proposed Rules.

[4] The estimate of 44 million metric tonne s per year (as of 2007) is contained among the Technical Supporting documents re ferenced in the Proposed Rule. See Meyer, "Summary of Carbon Dioxide Enhanced Oil Recovery (CO2 EOR) Injection Well Technology," (EPA Document Identifica tion: EPAHQ- OW-2008-0390-0018), prepared for the American Petroleum Institute ( published by API September 18, 2007), at 5 (Table 3) (noting annual U.S. CO2 inject ions of 0.044 GMT) (her eafter "Meyer"). While the Meyer document is not availabl e from regulations. gov, it is published on the Ground Water Protecti on Council’s website at: http://www.gwpc.org/e-library/documents/c o2/API%20CO2%20Report.pdf (visited November 10, 2008). As noted below, injections app ear to have increased in 2008.

[5] EPA Document Identification EPA-HQ-OW-2008-0390-0073, available at: http://www.regulations.gov/fdmspu blic/ContentViewer?objectId= 09000064806418c4&disposition=attach ment&contentT ype=pdf (last visited November 10, 2008).

[6] Transactions to purchase CO2 at seve ral such facilities we re first announced over two years ago and the development pro cess for these projects is continuing to move forward. See, e.g., Press Release, Denbury Resources, Inc. "Denbury Resources Inc. Acquires Option to Purcha se another Tertiary Flood Candidate; Agreement to Purchase Manufactured S ource of CO2" (November 8, 2006); Press Release, Denbury Resources, Inc. "Denbury Si gns Agreement to Purchase Additional Manufactured CO2" (June 25, 2007); DKRW Advan ced Fuels, LLC, "Medicine Bow Fuel and Power, LLC Fact Sheet") (coal-to-liquids plant planned near Medicine Bow, Wyoming). See also Application for Certification of Hydrogen Energy International, LLC (filed July 31, 2008 w ith California Energy Commission in docket 08-AFC-8) (proposed IGCC plant to ga sify petroleum coke (or blends of petroleum coke and coal, as needed) to produce hydrogen-rich synthesis gas for power generation while capturing approxi mately 130,000 Mcf/d of CO2 to be transported less than 3 miles for use in EOR and sequestration (storage)).

[7] See summaries of ongoing DOE-sponsored re search projects on geologic storage of CO2 at: http://www.netl.doe.gov/technol ogies/carbon_seq/core_ rd/storage.html (last visited November 8, 2008).

[8] A Class II well is defined in part as a well which injects fluids "[f]or enhanced recovery of oil or natural ga s." 40 C.F.R. § 146.5 (b) (2). Presumably, injections beyond those needed for enhanced recovery of oil or natural gas would no longer meet this definition.

7[9] Even after the deployment of the 22nd projected plant in the year 2030, total CO2 injections would appear to be significantly less than - perhaps only half - the current CO2 inject ions for EOR. Compare Meyer, supra, n. 4 with EPA, "Cost Analysis for the Proposed Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequ estration Wells (Proposed GS Rule)" (Document EPA-HQ- 2008-0390-0098), at page 3-6 (Exhibit 3.1 showing scheduled deployment of projects assumed in the baseline over the 25- year timeframe) and at page 5-37 (E xhibit 5.27 showing projected cumulative injections of 373.1 million metric tonnes dur ing study period). See also 73 Fed. Reg. at 43,527 (stating that Cost Analysis assumes that 22 projects will inject 350 Mt CO2 cumulatively over the next 25 years). This suggests average CO2 injections from power plants of approxi mately 14.92 million metric tonnes per year over the next 25 years, or rough ly one-third the level of current injections of approximately 44 million metric tonnes (as estimated by Meyer). See also Table 5, "Baseline Forecast of CO2 Sequestration Site Startups and Injected Volumes", in "Technical Suppor t Document: Geologic CO2 Sequestration Activity Baseline" (June 2008) (Prepared by IC F International) (EPA Document ID No. EPA-HQ-OW-2008-0390-0072) (posted by EPA July 25, 2008) (showing annual baseline projection for CO2 sequestra tion for twenty-five year period 2012-2036).

Individual Response: The final Class VI regulations re quire that any owner or operator injecting CO2 for the primary purpose of long term storage obtain a Class VI permit with some special consideration for the fact that they are transitioning from a well not originally designed to meet Class VI requirements. The Di rector has the authority to dete rmine at what point a Class VI permit is required for those projects that are transitioning from the primary purpose of EOR to long term storage of CO2. The fina l regulation provides a set of tec hnical factors for the Director to evaluate in making this determination, at §144.19. EPA believes that th is approach provides sufficient protection of USDWs when there is an increased risk to USDWs as compared to traditional Class II operations while allowing for site-specific flexibility.

EPA clarifies that inject ion of carbon dioxide for the purpose of enhanced recovery is regulated under Class II requirements. Owners or operators may use depleted oil and gas reservoirs for GS provided the injection is intended for long-term storage and the well m eets the standards in §146.86(a). EPA is allowing the construction of Cl ass II EOR wells to be grandfathered per §146.81(c), provided the owner or oper ator can demonstrate to the Director that the wells were engineered and constructed to meet the requi rements at §146.86(a) and ensure protection of USDWs from endangerment.

EPA disagrees that the rule need s to address a situation where re servoirs converted for GS would return to EOR production. EPA belie ves that pressure changes in the reservoir as a result of injection of high volumes of CO2 for GS woul d make future use of the reservoir for EOR unlikely.

EPA is developing guidance on transitioning perm its from Class II to Class VI. The guidance

8will assist Directors in determining whether an injection project should be transitioned from Class II, where the primary purpos e 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.

Letter ID: 0215 Comment ID: 24277 Letter Lines: 273 to 308

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: As currently crafted, the Proposed Rule may create unnecessary difficulty for EPA and the public by focusing initially on the more difficult future issues raised by potential storage of CO2 in deep saline formations, rather than on the much simpler issues that need to be a ddressed in the near term to allow for incremental storage of CO2 in formations where very large quan tities of CO2 are already being injected during Enhanced Oil Recovery operations. We urge EPA to consider complementing its current Proposed Rule with simplified or streamlined procedures that would govern incremental storage of CO2 at existing EOR or EGR sites following the termination of oil or gas production activity.

This transitional alternative could be a dopted in place of the current Proposed Rule that offers a limited transition m echanism for Class II wells or as an optional alternative. It sh ould of course include ve rification, monitoring and site closure requirements. If successful , the agency could then adapt those rules for less well understood formations such as deep saline formations and unmineable coal seams as the result s of ongoing research and the pace of deployment of capture technology for elec tricity power plants become better known.

Accordingly, Denbury urges EPA to bette r recognize the fruits of existing experience with injection and storage of large volumes of CO2 that are necessarily incidental to EOR opera tions. That existing experience is particularly important because it sugg ests strongly that the initial CO2 injections for geologic st orage purposes are likely to be made via existing Class II wells into previously defined and circumscribed underground oil or gas bearing formations.

We recognize that not all of the EOR i ndustry experience will necessarily apply to the movement of CO2 in saline forma tions that lack well defined boundaries or physical traps. It is precisely for that reason that it is important to continue research into the behavior of CO2 plumes in such formations. Nonetheless, where the CO2 has already been injected in previously defined reservoirs using

9approved well construction techniques and permitted by the proper state authorities, it should be possible to c ontinue CO2 injections for geologic storage purposes subject to appropriate additional monitoring, reporting and well closure-related requirements.

Individual Response: As described above, final Class VI re gulations require th at 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 traditiona l Class II operations while allowi ng for site-specific flexibility.

EPA clarifies that inject ion of carbon dioxide for the purpose of enhanced recovery is regulated under Class II requirements. Owners or operators may use depleted oil and gas reservoirs for GS provided the injection is intended for long-term storage and the well m eets the standards in §146.86(a). EPA is allowing the construction of Cl ass II EOR wells to be grandfathered per §146.81(c), provided the owner or oper ator can demonstrate to the Director that the wells were engineered and constructed to meet the requi rements at §146.86(a) and ensure protection of USDWs from endangerment.

EPA is developing guidance on transitioning perm its from Class II to Class VI. The guidance will assist Directors in determining whether an injection project should be transitioned from Class II, where the primary purpos e 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.

Letter ID: 0215 Comment ID: 24278 Letter Lines: 315 to 454 ; 1706 to 1782

Comment Code: 1800 1.4 Scientific Background/Informing the Proposal

Comment: A. Clarifying the record on "buoyancy"; the scale of current injections and storage; and corrosion

The U.S. Court of Appeals for the D.C. Ci rcuit has famously - and repeatedly - observed that there are some issues enc ountered by administrative agencies where "a month of experience will be worth a year of hearings."[FN10] In the case of CO2 injection and incidental storage dur ing EOR operations, the state permitting agencies and the oil and gas industry do not have a mere month of experience, but nearly four decades’ worth. Accordi ng to the documents in the current

10record, state permitting authorities have issued permits for approximately 13,000 Class II wells to inject CO2 for EO R operations, over 6,000 of which are actively injecting each year in excess of 44 million metric tonnes of CO2.[FN11] While that experience is focused on inj ections into well-defined oil and gas bearing formations, rather than salin e formations, many of the operational lessons learned relate directly to ap propriate well constr uction requirements for CO2 injection wells, corrosion mana gement for injection and production wells, as well as pipelines and associ ated CO2 handling facilities. We respectfully urge EPA to give greater weight to that extensive real-world experience than currently give n under the Proposed Rule.

The NOPR appears to downplay such actua l experience in the belief that the volumes, pressures, and certain physical characteristics of the CO2 injectate for geologic storage are "unique."[FN12] The basis for the belief that CO2 injectate for geologic storage is "unique" is apparently based on three specific factors:

(a) the "buoyant" natu re of CO2;[FN13] (b) the large scale of CO2 injections antic ipated to be captured from coal-fired power plants as compared to CO2 inj ections for EOR purposes;[FN14] and (c) the corrosivity of CO2 in th e presence of free water.[FN15]

The Proposed Rule thus states that th e regulatory alternative selected was chosen "because of the volumes of CO2 be ing anticipated for long-term storage, the buoyant and viscous nature of the inje ctate, and its corrosivity when mixed with water." 73 Fed Reg. at 43,504 (emphasis added). As shown below, however, the Proposed Rule mischaracterizes key facts with regard to these points.

1. CO2 is not inherently "buoyant"; rath er it is simply denser than some underground gases, fluids or liquids, while less dense than others. Such relative differentials in density do not cr eate an upward "force" as suggested by the NOPR’s definition.

The preamble to the Proposed Rule makes ve ry clear that the changes to the UIC program for CO2 sequestration are base d on the assertion that CO2 is "buoyant."[FN16] This is simply inco rrect. CO2 is a non-explosive, nonflammable, non-toxic gas that possesses di fferent physical properties than some other injectates. These physical properti es do not include any special buoyancy characteristics or properties. Rather, CO 2 is simply more dense than some underground fluids or gases and less dense than others. Hence the movement of injected CO2 in a reservoir, or any type of system containing different fluids or gases, will vary based on the relativ e densities of the various fluids or gases that are in the reservoir. The va rious materials will simply segregate based on the relative densities of the fl uids or gases including the CO2. As a result, CO2 may be the fluid that sinks to the bottom, rises to the top, or resides somewhere in between the top and the bottom flui ds within the system.

11For example, if CO2 is injected in a sy stem that contains water then the CO2 will at least initially rise to the top of the system. This seems to be the situation that the Proposed Rule assumes will always be the case. However, if CO2 is injected into a system that cont ains natural gas (i.e., methane), the CO2 will sink to the bottom of the system, belo w the natural gas, which will remain on top. That does not mean that the meth ane has suddenly become "buoyant" as defined by the Proposed Rule or exerts a ny incremental "upward force." Nor does it mean that CO2 acquires some special dow nward force. It simply means that natural gas is relatively le ss dense than the CO2 and he nce the two substances will tend to separate with the natural gas above the CO2. To reiterate: the relative depths, pressures and fluids w ithin the system will determine the densities of the fluids within the system and the relative location of each fluid within the system. CO2 has no special or unique "buoyancy" that causes it to exert an independent "force" in an underground reservoir.

This is recognized in the technical s upporting documents for the Proposed Rule. For example, the Vulnerability Evaluati on Framework [FN17] explains that:

Supercritical CO2 is less dense and mo re buoyant than oil and 30% to 50% more buoyant than saltwater. As a re sult, injected supercritical CO2 will rise to the top of depleted oil or deep saline formations. In contrast, supercritical CO2 is denser than natural gas, and will sink when injected in depleted gas reserv oirs. As temperature increases, the density of supercritical CO2 decr eases at a given pressure, but increases with increasing pressure at a given temperature. Similarly, the viscosity of supercritical CO2 de creases with increasing temperature at a given pressure, but increases wi th increasing pressu re at a given temperature. As temperature and pressu re increase with subsurface depth, the density and viscosity of superc ritical CO2 injected will be determined by the specific pressure and temperature conditions. Finally, when CO2 dissolves, it shares the ph ysical properties of the substrate (e.g., saltwater) and no longer behaves independently.

The Proposed Rule does not incorporate th is understanding, and instead appears predicated on the perception that CO2 exercises an upward force, as stated in the definition of the term "buoyancy" in the Proposed Rule. The Proposed Rule defines "buoyancy" as:

upward force on one phase (e.g., a fluid) produced by the surrounding fluid (e.g., a liquid or gas) in wh ich it is fully or partially immersed, caused by differences in pressure or density.

73 Fed. Reg. at 43,493 (emphasis added). Th is use of the word "force" is scientifically inaccurate and generates connotations that there are additional forces created when CO2 is injected in to the subsurface for sequestration. This

12is not the case, however, as there ar e no additional or different forces associated with CO2 injections than ther e are with the injection of any other fluid or gas. The injection of any fluid into the subsurface cr eates a transient pressure wave that is great er at the injection site a nd diminishes significantly at positions located away from the inj ection site. The separation of fluids within a formation due to their relative densities does not create any new or additional forces.

Much of the proposed rule appears to fo cus on the injection of CO2 into deep saline formations. In these formations, the injected CO2 would indeed tend to be relatively less dense than the existing saline fluids and hence the saline fluids would tend to sink towards the bo ttom of the formation relative to the CO2 and so migrate underneath the CO2. This tendency of saline fluids to segregate out below the CO2 does not e ndow the CO2 with any buoyant force, however. The issue is not "buoyancy," but me rely the anticipated movement of the CO2 in a particular geologic formation relative to other formation fluids.

In the NOPR’s discussion of regulatory alternatives considered by EPA, the "buoyant and viscous nature of the inj ectate" is cited as a key reason why "...EPA is proposing changes to the exis ting UIC approach or requirements in several program areas..." 73 Fed. Reg. 43,504. This misunderstanding of how injected CO2 behaves underground is repeat ed at multiple points in Sections 1, 2, 3, 4, 5 and 8.[FN18] The fact that the si gnificant new regulatory regime set forth in the Proposed Rule is based to such a great extent on factually and technically erroneous informa tion is of serious concern.

EPA should acknowledge this error and correct the factual predicate for its assumption that CO2 somehow "wants to get out" of the storage formation. Taken together with additional better informed assumptions on which the rule is based (discussed below), this necessarily sh ould lead EPA to find the existing UIC methodologies and rules generally suffici ent to address CO2 injections for geologic storage in oil and gas bearing formations. In other words, Class II regulations and requirements should be us ed with the addition of requirements for long term monitoring if, for exampl e, an operator of a well desires to convert an operation to a geologic storage site at the termination of EOR operations. Class II regulations and requi rements have proven successful in protecting underground sources of drinking water for al most 40 years and thus modifications or additions are more appr opriate than establishing a completely new well classification.

[10] American Airlines, Inc. v. Civi l Aeronautics Board, 359 F.2d 624, 633 (D.C. Cir., 1966) cert. denied, 385 U.S. 843, 87 S. Ct. 73, 17 L. Ed. 2d 75 (1966) (opinion en banc by Levantha l, J.). Judge Levanthal’s opinion has been applied in numerous cases involving a number of regulatory schemes including, for example, natural gas regulation (America n Public Gas Ass'n v. Federal Power Commission, 567 F.2d 1016, 1032 (D.C. Cir. 1977) and Maryland People's Counsel

13v. F.E.R.C., 761 F.2d 768, 779 (D.C. Cir. 1985) (same, but finding FERC program insufficiently explained or supported)); communications regulation (United Telegraph Workers, AFL-CIO v. F.C.C ., 436 F.2d 920, 925 (D.C. Cir. 1970)); and commodities regulation (Commodity Exchange v. Commodity Futures Trading Comm’n, 543 F. Supp. 1340, 1351 (S.D.N.Y., 1982)).

[11] Meyer, supra, n.4, at 2 (EPA Document Identification: EPA-HQOW-2008-0390-0018). See also John A. Veil and Markus G. Puder, "Evaluation of State and Regional Resource Needs to Manage Carbon Sequestration through Injection" (June 2007) (EPA Document Identification EP A-HQ-OW-2008-0390- 0084.pdf) (available also from the Ground Wate r Protection Council’s website at:http://www.gwpc.org/elibrary/ e-library_documents/elibrary_documents_co2/Argonne%20Report%20 CO2%20Resources.pdf (last visited November 10, 2008) at 8 (Table 3) (listi ng CO2 injection wells by state and by UIC well class)). The number of active CO 2 injection wells is also published in the Annual Production Report, Oil & Ga s Journal, vol. 106, (Apr. 21, 2008).

[12] The term "unique" is ubiquitous in the Proposed Rule in describing CO2 injections for geologic st orage. See e.g., NOPR, supra, 73 Fed. Reg. at 43,492, 43,495, 43,502, 43,504, etc.

[13] See citations at n. 16 infra.

[14] See citations at n. 19 infra. See al so EPA Cost Analysis, supra, at page 3-4 (stating that volumes to be inject ed for GS are "much greater" than traditionally seen in enhanced oil and ga s recovery operations, "which currently inject CO2 on a relatively small scale.")

[15] See citations at n. 26 infra.

[16] See, e.g., 73 Fed Reg. at 43,493 (def ining buoyancy as "[u]pward force on one phase (e.g., a fluid) produced by th e surrounding fluid (e.g., a liquid or a gas) in which it is fully or partia lly immersed, caused by differences in pressure or density); 73 Fed. Reg. at 43,494 (stating th at physical trapping occurs "when buoyant CO2 rises in the fo rmation until it reaches a layer that inhibits further upward migration or is immobilized in pore spaces due to capillary forces"), at 43,495 (same); at 43,499 (EPA evaluated risks of CO2 injection to USDWs to determine how best to tailor the existing UIC regulations "to address the buoyant and viscous propertie s of CO2 and the large volumes that could be injected); at 43 ,504 (EPA proposing changes "because of" the volumes of CO2 anticipated for long-term storage, the buoyant and viscous nature of the injectate, and its corrosivity when mixe d with water); at 43,505 (stating that "buoyancy of CO2 necessitates good characte rization of potential conduits for fluid migration upward through the conf ining system to USDWs); at 43,506 (referencing the "complex multi-phase buoyant flow of the CO2"); id. (stating that computational models used to delinea te the area of review consider inter

14alia the "buoyant nature" of the in jected CO2); at 43,509 (basing proposed enhancement to deep well construction procedures "[d]ue to th e buoyancy of CO2" in order to provide additional barriers to CO2 leakage outside of the injection zone); at 43,512 ("buoyancy of CO2" and la rge volumes may warrant improved leak detection of geologic storage wells even though use of tracers is not included in existing deep well requirements); at 43,513 (current mechanical integrity testing requirements will need to be tailored for CO2 storage to address the "unique properties of CO2, specifi cally its buoyancy and potential corrosivity"); id. (same, referencing n eed for tailored testing requirements "because of the buoyant and corrosive proper ties" of the CO2 in jectate stream); at 43,514 (basing increase in frequency of mechanical in tegrity testing in part on the "buoyant nature of the injected fluid that tends to force it upward toward USDWs"); at 43,519 (stating that area over which CO2 will spread is likely to be larger than for existing we ll classes "[g]iven the buoyancy of CO2, viscosity, and large injection volumes" a ssociated with geologic storage of CO2); and at 43,528 (stating that curr ent regulatory requirements do not specifically consider "injection of a buoyant corrosive fluid").

[17] EPA, "Vulnerability Evaluation Framework for Geologic Sequestration of Carbon Dioxide" (July 10, 2008) at 76-77 (Appendix A) (internal citations omitted).

[18] See citations in note 16, supra. The other primary reasons for which a special rule is required for CO2 are the large volumes, and the corrosive nature of the CO2 injectate, which are discussed below.

Individual Response: EPA disagrees with the commenter that the risks involved in GS projects are the same as the risks associated with Class II activities. EPA believes that GS is sufficiently distinct from Class II ER operations to warrant the tailored requireme nts in the final GS regulation. For example, the volume of CO2 anticip ated to be injected in Class VI wells is significantly greater than for Class II wells. Reser voir pressure conditions will be different, with Class VI injection operations i nvolving large volumes of CO2 a nd likely having higher pressures within their storage formations than Class II ER projects. Therefore, Class VI GS reservoir pressures will increase more in comparison to Cl ass II ER during the inj ection phase of the GS project.

EPA disagrees with the commenter that the buoyan cy of CO2 is not an important consideration. Based on reviews of existing project reports and fundamental research, including many multiphase fluid modeling studies, EPA believes that the lower density of CO2 relative to groundwater will result in eventual upward m ovement of CO2, or "buoyancy." The buoyancy of CO2 is unique compared to many other inject ed fluids currently regulated under the UIC Program. For example, seismic surveys at Sleipner showed that CO2 had migrated to the top of the 200 to 300 meter thick forma tion as early as thr ee years after inject ion began. Data and information from the Sleipner project show that the injected CO2 migrat ed to the top of the formation and spread laterally (Chadwick et al 2006). Buoyancy may result in CO2 movement into a USDW if an appropriate, impermeable ge ologic confining zone is not present to stop

15upward movement or if there are artificial pene trations or other high permeability features present.

EPA continues to research and collect data on CO2 storage and containment. EPA is tracking operations at the DOE GS pilot projects and will review data on all aspects of those operations, from well construction and injection to long-term plume fate and transport and monitoring of containment, as the data become available. In ad dition to the information cited in the preamble to the proposed rule, EPA published a Notice of Da ta Availability and Request for Comment on August 31, 2009 (74 FR 44802), in which the Agency de scribed the results of research at three DOE partnership sites: the Escatawpa, Mississi ppi project; the Aneth Fi eld project in Paradox Basin, Southeast Utah; and the Pump Canyon Site, New Mexico.

EPA is using an adaptive approach to regulati ng GS. The Agency plans to collect and review data every six years on GS projects to determ ine whether the appropria te amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Letter ID: 0215 Comment ID: 24279 Letter Lines: 456 to 527 ; 1784 to 1825

Comment Code: 1800 1.4 Scientific Background/Informing the Proposal

Comment: 2. Contrary to statements in the NOPR, th e scale of CO2 injec tions anticipated to be captured from coal-fired power w ill be far less - not greater - than the scale of existing CO2 injec tion operations for many year s and therefore does not justify the proposed new regul ations at this time.

The second basis for the Proposed Rule’s conclusion that CO2 injections for geologic storage are "unique" is the st atement that the scale of these injections will be on a scale that is much larger than other types of UIC injection operations.[FN19] Th is is simply erroneous. For example, the EPA Cost Analysis assumes cumulative injections of 350 million metric tons of CO2 over the next 25 years.[FN20] Yet as the NOP R itself recognizes, this is only about half the quantity of CO2 that has alre ady been injected in oil and gas production operations - for as the NOPR notes (at 43 Fed. Reg. 43,503) a study prepared for the American Petroleum Institute estimated in 2007 that some 600 million metric tonnes had already been injected. The study referenced by the Proposed Rule further evaluated current a nnual injections at approximately 44 million metric tones per year.[FN21] These quantities have been increasing in recent years. For example by early 2008, Denbury alone was producing and transporting over 700,000 Mcf/d of CO2 - th e equivalent of approximately 13.4 million metric tonnes -- the great major ity of which was injected for EOR operations.[FN22] In other words, the scal e of operations of this one company - which is not the largest pa rticipant in the EOR industr y - is essentially the same by itself as EPA’s projected averag e injection rate for geologic storage for the entire nation of 14 million tonnes per year over the next 25 years (as

16published in the NOPR’s Cost Analysis (350 million metric tonnes cumulative injections over 25 years divided by 25 years = 14 million tonnes per year)).[FN23]

Put another way, at current rates, the na tion’s EOR operators will inject more CO2 through Class II wells in the next 7 or 8 years than the total quantities of CO2 projected to be injected via the new Class VI wells over the next 25 years - assuming that CO2 capture at power plants is in fact deployed on a commercial scale during that time. In sum, the new requirements in the Proposed Rule cannot be supported on the erroneous statement that CO2 injections under Class VI rules will be materially greater than those under the current Class II rules, when the reverse is true today and (accepting EPA’s own estimates for the future rate of deployment of carbon capture technology at pow er plants) is expected to remain the case for decades. It is only in some distant future that injections of powerplant CO2 are anticipated to appro ach the scale of current operations (which may also expand). Hence the simple scale of CO2 injection operations of captured CO2 is not "unique" and is not expected to become a relevant distinction for at least the next several decades.

Similarly, where the Proposed Rule states that it is "generally agreed" that over time the CO2 plume and pressure front associated with a full-scale GS project will be much larger than for other types of UIC injection operations,[FN24] this statement is no t borne out by the facts. While not defined in the Proposed Rule, a "full-scale" GS project might, for example, be a project capable of accommodating the CO2 cap tured from a 500 MW power plant, or roughly 2.4 million metric tonnes per year [FN25] - an average of just 6,575 metric tonnes per day. This amounts to le ss than 5 percent -- one-twentieth -- the level of current Class II CO2 injec tions (50 million metric tonnes divided by 2.4 million = 0.048). It is thus simply not accurate to conclude that it is "generally agreed" the CO2 plume and pre ssure front of a full- scale GS project will be "much larger" than for CO2 inject ions for EOR purposes; the facts are quite the reverse: The scal e of current CO2 injections through existing Class II wells is already vastly larger than the s cale of the CO2 injections expected for the new Class VI wells for the foreseeable future.

This does not mean that there will be no differences between CO2 injections for geologic storage versus EOR operations, or that new rules ar e not appropriate for long term sequestration, especially when dealing with deep saline formations for storage. However, it does strongly sugge st that what is ne eded today is not so much a fully developed set of rules to govern injections of power plant CO2 into saline formations, as a framewor k for allowing the transition of the existing and planned universe of CO2 wells from EOR operations to long term geologic sequestration operations. Furthe r development of rules for injecting and storing CO2 in non-oil and gas bearing formations such as deep saline formations could then be undertaken. At th at point, such rule s would properly be based on additional years of research regarding the movement of a CO2 plume in a

17saline formation, the experi ence of the state Director s with monitoring and remediation activities, etc.

[19] See, e.g., 73 Fed. Reg. 43,506 (stating th at it is "generally agreed" that over time, the CO2 plume and pressure front associated with a full-scale GS project will be "much larger" than for ot her types of UIC inj ection operations); 73 Fed. Reg. at 43,518 (requirement to a ddress the "unique and large-scale nature of CO2 GS operations"); and 73 Fed. Reg. at 43,527 (stating that Cost Analysis assumes that 22 projects will inject 350 Mt CO2 cumulatively over the next 25 years). See also EPA Cost Analys is, supra, at page 3-4. (stating that volumes to be injected for GS are "muc h greater" than traditionally seen in enhanced oil and gas recovery operations, "which currently inject CO2 on a relatively small scale").

[20] 73 Fed. Reg. at 43,527. This estimat e is within the range of other published estimates. For example, the IP CC Special Report in 2005 estimated CO2 pipeline transport in the U.S. (most of which is injected for EOR purposes) at 50 million metric tonnes per year and sepa rately estimated CO2 injections for EOR at about 30 million metric tonnes per year. IPCC Special Report, at 181 (for transport) and at 203 (for injection)

[21] Meyer, supra, n. 4 "Summary of Car bon Dioxide Enhanced Oil Recovery (CO2 EOR) Injection Well Technology," prepared for the American Petroleum Institute (published by API September 18, 2007), at 5 (Table 3) (note stating 0.044 GMT of CO2 injected per year) (EPA Document EP A-HQ-OW-2008-0390- 0018). As noted above, the report is not accessible through the regulations.gov website, but may be accessed either from the Ground Water Protection Council’s website at: http://www.gwpc.org/elibrary/ documents/ co2/API%20CO2%20Report.pdf (visited November 10, 2008) or from the American Petroleum Institute at http://www.api.org/aboutoilgas/sectors/ex plore/upload/API_CO2_Report_August2007.pdf (last visited November 17, 2008).

[22] See 2007 Annual Report of Denbury Re sources, Inc. (Form 10-K), at 6 (converting Mcf to metric tonnes by dividing by 19.1).

[23] See references in note 9, supra.

[24] 73 Fed. Reg. at 43,506.

[25] The estimate of 3 million metric t onnes per year output of CO2 from a 500 MW plant is taken from the MIT report, "The Future Of Coal: Options For A Carbon-Constrained World" at 24-39, (hereafter "The Fu ture of Coal") at 105 (available at http://web.mit.edu/coal/ (last visited May 6, 2008)). Assuming that 80 percent of the CO2 output were captured, there would be 2.4 million Mt CO2 available for injection and storage.

18Individual Response: EPA disagrees with the commenter that the risks involved in GS projects are the same as the risks associated with Cl ass II activities. EPA iden tified unique challenges posed by large-scale GS, including large inject ion volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations that warrant the tailored approach in the GS rule. As discussed in the preamble to the final GS rule, available data currently supports these findings.

EPA is using an adaptive approach to regulati ng GS. The Agency plans to collect and review data every six years on GS projects to determ ine whether the appropria te amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

In response to the comment about the anticipa ted scale of GS, EPA acknowledges that initial deployment of GS technology may be limited. However, EPA analyses of Congressional climate change legislative proposals (the American Clean Energy and Security Act H.R. 2454 and the Lieberman-Warner bill S. 2191) in dicate that CCS has the potential to play a signif icant role in climate change mitigation scenarios. For exam ple, analysis of H.R.2454 indicates that CCS technology could account for 10 percent of CO2 emission reductions in 2050 (see EPA's June 2009 H.R. 2454 analysis at: http://epa.gov/climatechange/economics/econom icanalyses.html#hr2454). Under any approach to address GHG emissions, CCS offers great po tential for significan t reductions in CO2 emissions. The President's CCS Task Force report (August 2010) also considered barriers to rapid deployment of CCS technologies.

Letter ID: 0215 Comment ID: 24280 Letter Lines: 529 to 639 ; 1827 to 1876

Comment Code: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment) Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)

Comment: 3. The Proposed Rule overstates the corro sivity of CO2, whic h is not at all corrosive except in the presence of free water.

The third basis for the Proposed Rule is th e potential corrosivit y of CO2.[FN26] The Proposed Rule specifically seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant cements and corrosion-resistant casing. The NO PR correctly states that CO2 mixed with water will form carbonic acid (H2CO3) and that carbonic acid is corrosive of cement -- a fact that has long been taken into account in existing permitting procedures and industry practices. Howeve r, the preamble to the Proposed Rule appears to overstate the corrosivity of CO2 under actual geologic storage conditions. For example, the NOPR refere nces (73 Fed. at 43,510) the actual field experience and observations from wells that had been exposed to a CO2- water environment for 30 years, but then appears to largely dismiss the results

19on the grounds that this ac tual field corrosion experien ce is "surprisingly" low (presumably in light of a referenced labor atory study that found much more rapid corrosion than has in fact been experien ced).[FN27] In contrast, a study that reviewed actual samples exposed to a CO2-water environment for 30 years was seemingly dismissed as involving "o nly limited examples," while the contradictory laboratory st udy was apparently given greater weight.[FN28]

The Proposed Rule appears to downplay othe r research publications that conclude that conventional Portland-based well cemen ts have been adequate to guard against corrosion from CO2 mixed with wa ter. For example, the Proposed Rule cites Meyer (2007)[FN29], but doesn’t recognize that Meyer notes that nonPortland cements have not been widely us ed in CO2 EOR applic ations, and have been applied instead to resi st "very severe acid gas (CO2 and H2S) and highly corrosive geothermal brine exposure condi tions." Meyer (2007) , supra, n. 4 at 18. Dr. Meyer also noted the actual expe rience from a 52 year old well with conventional, Portland-based well cement, that had been exposed to CO2 for 30 years in EOR operations and no significan t wellbore failure had been observed. Id. (referencing Carey, et al. 2007).[FN 30] Indeed, Carey, et al., concluded from the review of actual cement exposed to CO2 for 30 years that "[t]he casing was in excellent condition and showed little evidence of corrosion." Carey, et al., at 76. While the Portland cement did s how evidence of exposure to CO2, the structural integrity of th e recovered cement core, pe trographic observations, air permeameter data, and cement bond log i ndicated that "the cement retained its capacity to prevent significant tr ansport of fluid through the cement matrix." Id. at 84; see also at 78 ("no obvious evidence for CO2 interaction" inthe shale caprock); id. (core bond log showed "no evidence of CO2- induced debonding or channel formation at or near the reservoir contact"); id. ("most basic observation of the SACROC core" is that the Portland cement at the studied well "survived and retained its structural integrity after 30 years in a CO2- reservoir environment").

Finally, the record here should be suppl emented with additio nal laboratory research published after the Proposed Rule, the results of which suggest a rate of degradation of Portland cement unde r conditions mimicking geological sequestration that is far less than th e study cited in the Proposed Rule. See Kutchko, et al. "Rate of CO2 Attack on Class H Well Cement under Geologic Sequestration Conditions" (hereafter Kutc hko, 2008).[FN31] While the details of the research merit careful consideration, and additional research is currently underway, the conclusion of this Augus t 2008 research publi cation is worth quoting:

Based on the alteration process, pe netration depths, and rates of alteration observed in this study, and on penetration depths observed in field samples exposed to CO2 for ~3 0 years, it is unlikely that alteration of these cements via cement matrix diffusion of supercritical CO2 or CO2-saturated brine would lead to significant alteration in well

20completions that are properly cemented with Class H neat cement after decades of exposure to supercriti cal CO2 or CO2-rich brine.

Kutchko, et al.(2008), supra, at 6242.

This research is reinforced by other pape rs presented at a major international conference on greenhouse gas control t echnologies, the 9t h International Conference on Greenhouse Gas Control Technologi es (hereafter cited as "GHGT-9") that we commend to the agency’s atten tion, including in pa rticular:[FN32]

- Duguid, "An estimate of the time to degrad e the cement sheath in a well exposed to carbonated brine," summarizing (at 3-4) recent physical re search on cement carbonation and describing own research. In sum, Duguid’s recent experiments indicate (at 8) that for a well that ha s good zonal isolation and no pathways for flow, "the rate of degradation wi ll be between 30,000 and 700,000 years to degrade 25 mm of neat paste in a sandstone reservoir, and po ssibly longer to destroy the cement passing through the cap rock."[FN33]

- Crow, Williams, Carey, Celia, and Gasda, "Wellbore integrity analysis of a natural CO2 producer," at 8 (concluding, inte r alia from analysis of 30 year old well from a natural CO2 production reservoi r that Portland-based cement systems "can be used effectively in creating su itable barrier systems for long-term CO2 storage operations, if good practices are employed duri ng well construction");

- Benge, "Improving wellbore seal integrity in CO2 injection wells" (reviewing recent research and noting (at 2) that applying the formula developed by BarletGouedard, et al., it would take "several hundr ed centuries" - tens of thousands of years -- to degrade 6 meters of wellbore cement (even assuming a continuous and renewable supply of fresh CO2 with no ot her inhibiting reacti ons occurring).

- Aiken, "An Introduction to the IEA GHG International Research Network on Wellbore Integrity." The paper reviews th e work of the IEA’s International Research Network on Wellbore Integrity f ounded some 4 years ago and noting (at 1, 6) the importance of analyzing th e differences found between laboratory experiments and corresponding field findi ngs, and if necessary, designing new laboratory experiments to bette r replicate field conditions.

A great deal of other orig inal research was presente d as well, underlining the dynamic nature of research in this area and reinforcing the importance of avoiding overly-prescrip tive requirements that ar e unnecessary based on experience in the field.

We concur with the Proposed Rule’s ge neral principle that cement and cement additives must be "compatible with th e carbon dioxide str eam and formation fluids" and "of sufficient quality and qua ntity to maintain integrity over the design life" (Section 146.86 (b) (5)). However, we are co ncerned that the rule

21contains prescriptive well construction and monitoring requirements that do not appear necessary in light of actual field experience and the more recent laboratory research referenced above. At a minimum, the more recent research suggests that EPA should defer imposing these additional costly requirements pending the fruits of the further field experience and research.

[26] See 73 Fed. Reg. at 43,503 (design cha nges are being propos ed to address mobility "and corrosivity" caused by long te rm GS of CO2); id., at 43,504 (EPA proposing changes "[b]ecause of" the volumes of CO2 being antic ipated for longterm storage, the buoyant and viscous nature of the injectate, "and its corrosivity when mixed with water"); i d. at 43,509 (pointing to the "potentially corrosive nature of the injectate" in the design and constr uction of CO2 GS wells and noting that "CO2 mixed with wa ter or impurities (NOX, SOX and H2S) can be corrosive to well materials and cem ents" and expressing concern that "conventional" cement formations (e.g. Portland cement) are "potentially vulnerable" to acid attack).

[27] 73 Fed. Reg., at 43,510

[28] Id. ("[a]though the field corrosion looks surprisingly low, these are only limited examples. Laboratory studies are conducted under aggressive chemical conditions in an attempt to mimic the cumulative effects of long-term exposure to CO2-rich formation fluids. Given the high injection rates, long lifespan, and potential impurities in GS, careful selection of acid -resistant materials and practices may be necessary).

[29] Meyer, supra, n.4.

[30] Dr. Meyer references the pre-publication version of Carey, J.W., M. Wigand, S.J. Chipera, G. WoldeGabriel, R. Pawar, P.C. Lichtner, S.C. Wehner M.A. Raines and G.D. Gutherie Jr., "Analysis and Pe rformance of Oil Well Cement with 30 Years of CO2 Exposure from the SACROC Unit, West Texas, USA," preprint submitted to International Journa l of Greenhouse Gas Control, October 18, 2006. The citation to the published report is 1 In ternational Journal of Greenhouse Gas Control, pages 75-85 (2007).

[31] Barbara G. Kutchko, Brian R. Strazisar, Gregory V. Lowry, David A. Dzombak, and Niels Thaulow, "Rate of CO2 Attack on Class H Well Cement under Geologic Sequestration Conditions," Environmental Science and Technology, vol. 42, number 16 (August 15, 2008), at 6237-42.

[32] "GHGT-9, 9th International C onference on Greenhouse Gas Control Technologies," (November 16-20, 2008) Wa shington DC (http://mit.edu/ghgt9/) (hereafter "GHGT-9 Conference" (organized by MIT in collaboration with the IEA Greenhouse Gas R&D Programme (IEA GHG), with major sponsorship from the U.S. Department of Energy). All papers pres ented at the GHGT-9 Conference are

22available from the conference website at: http://mit.edu/ghgt9/ papers/index.html (last visited December 12, 2008) and th rough the site’s search portal at: https://www4.eventsinteractive.com/iea/ rs.esp?id=270005&scrip tid=sppp1 (last visited December 12, 2008).

[33] It should be noted that these resu lts are quite different than in a 2006 paper by some of the same researcher s which EPA included among the supporting materials in this proceeding. Compare A. Duguid, M. Radonjic, R. Bruant, T. Mandecki, G. Scherer, and M. Celia "The Effect Of CO2 Sequest ration On Oil Well Cements" (Document ID: EPA-HQ-OW-2008- 0390-0013) (posted by EPA July 25, 2008).

Individual Response: EPA disagrees that the potential corr osion of well materials and cements when exposed to CO2 in the pres ence of water or other fluids is overstated. While some studies of cement performance have shown encouragin g results, other information gathered through stakeholder workshops, research, and field data provide evidence of ch emical alteration and suggest a potential for degradation to occur and potentially endanger USDWs.

Although the laboratory and field studies suggest that corrosion problems may not be severe, such problems cannot be conclusively ruled out, a nd the amount of available data on this topic is still limited. Laboratory explorati on of cement alteration and degr adation is an ongoing research area, and field-based studies are very few. There also does not appear to be a clear consensus on the corrosion risks for the steel components of injection wells. Given the anticipated long lifespan of Class VI wells and the difficulties that would be associated with a corrosion-related well failure, EPA believes that the construction requireme nts at §146.86 are justified.

EPA has reviewed the study by Meyer (2007) cited by the commenter, along with other laboratory and field-based research (Barlet-Gouedard et al., 2006; Kutchko et al., 2007, Carey et al., 2007, and Crow et al., 2008) that have shown Portland cement alterati on (carbonation) when the cement is exposed to CO2. While research indicates that cement alteration occurs, the alteration appears not to signi ficantly reduce the integrity or performance of the cement. However, under conditions simulating flowing CO2-sa turated brine, loss of structural integrity (more significant degradation) of cement was fo und in laboratory studies (Duguid et al. 2005), although it is uncertain whether wells in GS operations would be exposed to flowing CO2- saturated brine. The field-based studies that identi fied alteration reflect the results of relatively few samples from a very small number of wells , and the well material samples may have been exposed primarily to dry CO2. Cement degradati on and corrosion are a possibility, so the cement and cement additives used may need to be acid-res istant to meet the requirement that they are compatible with the CO2 stream, formation fluids , and the anticipated inj ection zone conditions.

Letter ID: 0215 Comment ID: 24281 Letter Lines: 641 to 657 ; 1878 to 1879

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

Comment: We would also call to EPA’s attention ot her recent research from the GHGT-9 Conference that is relevant to this rulemaking with re gard to the carbon content

23of oil that could be pr oduced via CO2 injection of captured CO2 emissions. Ferguson, et al. reviewed the net carbon c ontent of oil produced via CO2-based EOR, taking into account the storage of residual CO2 that rema ins stored as a normal incident of EOR production operati ons. The researchers calculated that oil produced through injection of captured CO2 emissions would be roughly 70 percent "carbon free" under current technology. See Fergus on, Nichols, Leeuwen, and Kuuskraa, "Storing CO2 with Enhanced Oil Recovery" ("Ferguson, et al. 2008") [FN34] The authors estimate that next generation CO2 storag e technology may allow for the produced oil to be "100+" percent carbon free and evaluate the potential size of the market for CO2 for these EOR purposes on the order of 7,500 million metric tonnes between now a nd 2030. This capability of the U.S. oil industry to reduce the net carbon conten t of new oil supplies is an aspect of the sequestration debate that is no t addressed in the Proposed Rule, but illustrates how targeted technological innovation can reduce carbon emissions while maintaining - indeed, growing - energy supply.

[34] Paper presented at GHGT-9 Confer ence and available from the GHGT-9 Conference website cited above.

Individual Response: EPA clarifies that the final Class VI GS rule does not require owners or operators to use GS technologies , nor does it impact business as usual for Class II owners or operators that are injec ting CO2 to enhance production of oil or gas. Those owners or operators that choose to transition from enhanced recove ry to GS may do so, provided they meet the requirements for Class VI wells.

EPA clarifies that the purpose of the Class VI GS rule is to ensure consistency in permitting underground injection of CO2 at GS operations across the United States and provide requirements to prevent endangerment of USDWs in anticipation of the eventual use of GS to reduce CO2 emissions. EPA agrees that GS is one technology in a portfolio of options, including energy conservation, efficiency improvements, a nd the use of alternative fuels and renewable energy sources, that could be deployed to reduce CO2 emissions.

Letter ID: 0215 Comment ID: 24282 Letter Lines: 659 to 708 ; 1881 to 1909

Comment Code: 1360 1.1.3.4 Effectiveness of trapping mechanisms Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment)

Comment: B. The Proposed 50-year Term for Post-Inje ction Site Care Is Unreasonably Long

Denbury strongly objects to the use of a 50-year timeframe for continuous monitoring during post-injection site care. Our objection stems from the relative risks associated with the various phase s of geologic storage operations, the recognized progression of various geologic trapping mechanisms (which means that risks of unexpected migration diminish over time), the creation of artificial impediments to fina ncial assurance and the sagacity of other regulatory proposals.

24First, we believe that pub lished and reputable literatu re suggests that a 50- year timeframe for post-injection site car e is too long and wholly unrelated to the risks associated with geologic st orage. For well-sited, characterized, operated and managed sites, the risks accumulate during the operational phase, but decline as sites move from post-inject ion site care to closure to eventual long-term care. Prevailing scientific opinion expects the risk profile to diminish with time.[FN35] As Lindene and Trabucchi suggest, "the risk of some events occurring that result in an unexp ected release of carbon dioxide more than 10 years after termination of injec tion will become increasingly remote due to geochemistry conditions ."[FN36] The geochemistry conditions they reference include the four main mechanisms which trap CO2 in well-chosen geological formations - 1) structural trapping -- wh ich is addressed in the proposed rule and is not necessary to discuss further here; 2) residual CO 2 trapping -- where CO2 is trapped by capillary forces in th e interstices of the rock formation, a process which develops about 10 years after injection; 3) dissolution or solubility trapping -- where the CO2 di ssolves into the brine found in the geological formation and sinks because th e CO2 saturated brine is more dense than non-CO2 saturated brine, a process taking place between 10 and 100 years after injection; and finally, 4) minera lization or mineral trapping -- which occurs when dissolved CO2 chemically reac ts with the formation rock to produce minerals, a process requiring hundreds of years.[FN37]

Given that the greatest risk of a release occurs during the operationa l stage of a storage project, and that residual and dissolution trapping start well in advance of 50 years, it is difficult to understand why a 50-year timeframe for post-injection site care was chosen. A 50-year post-injec tion site care timeframe simply does not correlate to the relative risks associated with geological storage and the function of ge ologic trapping mechanisms that limit the risk of unexpected releases of CO 2 after the termination of injection activity.

Furthermore, other respected models use a much shorter period. For instance, the IOGCC Model Rules and Legislation stipul ate a 10 year post-injection site care period.[FN38] Under the IOGCC Model, the op erator of the stor age site is the responsible party and is required to maintain an operational bond for the equivalent of a post-injection site care period and until closure. This 10 year post-injection site care period is more plai nly related to the re lative risks of geologic storage and the geoc hemical reactions discusse d above. Also, in the preamble, EPA acknowledges that a 30-year post-closure care pe riod is recognized as the industry standard for the inje ction of hazardous waste.[FN39]

[35] See Intergovernmental Panel on C limate Change, Special Report on Carbon Dioxide Capture and Storage, 208 (Bert, Me tz, et al. eds., 2005) ; see also Sally Benson, "Carbon Dioxide Capture and Storag e: Research Pathways, Progress and Potential," Global Climate & Energy Pr oject Annual Symposium, October 2007,

25available at http://pangea.stanford.edu/research/bens onlab/presentations/C arbon%20Dioxide%20C apture%20and%20St orage%20-%20Research%20Pathways%20Progre ss%20and%20Potential.pdf (hereafter "Benson 2007").

[36] Chiara Trabucchi and Lindene Patton, "Storing Carbon: Options for Liability Risk Management, Financial Responsibility," Daily Environment Report, Bureau of National Affairs, pg. 8 (Sept. 3, 2008).

[37] See IPCC Special Report on CCS, s upra n.2, at 208; see also Benson 2007, supra n.35.

[38] See generally IOGCC, "Storage of Carbon Dioxide in Geol ogic Structures: A Legal and Regulatory Guide for States and Provinces" (September 2007) (publishing Model Statute and Rules for CO2 storage). The proposed 10 year default period for maintaining operator re sponsibility is at M odel General Rules and Regulations, Section 2.0 (f) (defini ng "CSP Closure Period" as 10 years unless otherwise designated by the State Re gulatory Agency). See also at Section 4.0 (b) (10) (requiring performance bond to be maintained for 10 years after closure of the facility in accordance with Section 9.0) . The discussion of the Model Statute and Regulation also mentions other potential peri ods of "10 or 29 years, etc." IOGCC, supra, at 30.

[39] See 73 Fed. Reg. at 43,510.

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 believe s that the 50-year default time frame is warranted in most cases based on additional re view of research studies and reports and 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.

26Both approaches will utilize si te-specific data, and be based on pressure monitoring and USDW impacts.

EPA clarifies that, in determining the post-in jection site care-timef rame for the proposed regulation, EPA reviewed industry reports, exis ting environmental programs, and initial GS research studies. EPA provided a synthesis of pe rtinent results from GS modeling studies in the preamble to the proposed regulation. Further expl anation of this analysis was included in an EPA-prepared background document that is available in the federal docket, titled ""Computational Modeling of Underground Injecti on of Carbon Dioxide for Determination of Area-of-Review and Potential Risk to Underg round Sources of Drinking Water."" Based on review of these studies, modeling results indicate that the CO2 plume stabilization may occur on the timeframe of 10-100 years after the cessati on of injection. EPA be lieves that a 50-year default post-injection site care timeframe is a reasonable midpoint for most GS projects and available data, including data submitted by commenters, do not support a different default timeframe, and has retained th is in the final regulation.

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

EPA also recognizes the concerns associated with assuring fina ncial responsibil ity for the long time-frames over which post-injection site care w ill be conducted. However, the Agency believes that, in order to protect USDWs from endangerment under the SDWA, operators must demonstrate under §146.85 that fina ncial resources are available to plug the injection well and provide post-injection site care at the point in time that the first CO2 is injected. EPA is developing guidance on financial responsibility to assist owners or operators in evaluating the requirements of §146.85 and to assist Director s in evaluating financial responsibility demonstrations. The guidance desc ribes the types of financial m echanisms that operators may choose to use when evaluating th e financial responsibil ity requirements for GS wells and it will also include a section on how to estimate costs to support accu rate financial responsibility demonstrations. The guidance will be available at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0215 Comment ID: 24283 Letter Lines: 710 to 720

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) Comment Code: 5400 2.9 Proposed Financial Respons ibility and Long-Term Care Requirements

Comment: Finally, this 50-year timeframe raises ba rriers to obtaining financial assurance

27for prospective projects. Section 146.85 of the Proposed Rule requires the owner or operator to maintain financial responsibility for corrective action, injection well plugging, post- injection site car e and site closure. Undoubtedly owners/operators will enter the private s ector financial assurance market for some period in order to meet this require ment. An uncertain or a 50-year postinjection site care timeframe creates im pediments to managing this financial responsibility. We believe th at both an indeterminate or an exceedingly long post-injection site-care period will disc ourage the development of private sector products to address financial responsibility a nd discourage sequestration in general.

Individual Response: EPA disagrees that the requirements fo r financial respons ibility are overly stringent or unreasonable. The goal of financial responsibility is to ensure that financial resources are available to prevent the endangerment of USDWs from improper plugging, remediation, and management of wells in the event that the owne r or operator experiences financial difficulties throughout the life of the project. See the final ru le and preamble for further discussion of EPA's final approach to financial responsibility.

EPA believes that minimum financial responsibi lity requirements are necessary to hold well owners or operators accountable for the safe operation and proper si te closure of the well in order to protect USDWs while also avoiding expense a nd risk to the public. EPA adds that the purpose of the GS rule is not to encourag e the use of GS; rather, the purpos e of the GS rule is to ensure that, where GS is deployed, it is conducte d in a manner that protects USDWs from endangerment.

Letter ID: 0215 Comment ID: 24284 Letter Lines: 722 to 733

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

Comment: Given the limited risk profile of th e post-operational phase of geologic storage, the precedent set by other proposals, and the likely impediments to financial responsibility and insurance caused by an uncertain or exceedingly lengthy post-injection site care period, we think that a 50-year post-injection site care period is unsupported by the scie nce, unnecessary to protect USDWs and unwarranted by current EOR experience. While we agree that in most instances site-specific performance st andards are most appropriate , we believe that in this instance a definite a nd reasonable timeframe should be established that is supported by the relative risks involved a nd that facilitates the development of financial assurance products. We believe a 10 year post-injection site care period protects USDWs, facilitates post -injection financial assurance and is consistent with our understanding of how geologic trapping of CO2 occurs.

Individual Response: EPA disagrees that a post-injection si te care timeframe of 50 years is excessive in most cases or arbi trary. EPA proposed a default post-in jection site car e timeframe of 50 years based on a review of research studies , industry reports, and existing environmental

28programs. This analysis was included in an EPA- prepared background document that is available in the federal docket, titled "Computationa l Modeling of Underground Injection of Carbon Dioxide for Determination of Area-of-Review a nd Potential Risk to Underground Sources of Drinking Water." EPA assessed various default timeframes based on additional review of research studies and evaluation of public commen ts. While numerous commenters suggested that EPA shorten the monitoring timeframe, none of the commenters provided suffi cient data or other evidence to warrant a change in the proposed timeframe. While the 10- or 30-year timeframe suggested by some of these commenters may be within the timeframe suggested in some studies, EPA believes that the potential risks of endange ring USDWs will likely no t decline within these timeframes and available data, including da ta submitted by commenters, do not support a different default timeframe. However, EPA r ecognizes that alternative timeframes may be appropriate under limited, specific circumstances.

For this reason, the GS rule offers owners or op erators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director 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 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 believes however, that to ensure USDW protection from enda ngerment, a default timeframe for post-injection site care will be necessary in al l but a limited number of cases. This default 50 year post-injection site care ti meframe represents a reasonable and protective monitoring period based on a review of research studies, industr y reports, and existing environmental programs, and evaluation of public comments.

EPA 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.

To the comment about the cost of post-injection site care, EPA does not ag ree that post-injection site care timeframes longer than 30 years will be prohibitively expensive. In fact, EPA believes that post-injection site care monitoring will re present a relatively minor component of total project cost, and will provide an essential level of protection from endangerment for USDWs. A discussion of the costs attributed to monitori ng technologies (used durin g injection and the postinjection site care timeframes) is available in the Technology and Cost Document for the GS rule, which is in the federal docket for this rule making. EPA believes that it is logical to make

29use of existing monitoring infrastructure at a GS site in order to ensure USDWs are not endangered.

Letter ID: 0215 Comment ID: 24285 Letter Lines: 735 to 769 ; 1911 to 1914

Comment Code: 1630 1.3.3 RCRA/hazardous waste i ssues (seeking comment) Comment Code: 1640 1.3.4 CERCLA issues (seeking comment)

Comment: III. ANY FINAL RULE MUST CLEARL Y ADDRESS POTENTIAL EXPOSURE UNDER RCRA AND CERCLA

EPA can and should simultaneously protec t underground sources of drinking water and promote the capture of carbon dioxide. It s strategy in both areas should be crafted to avoid unintended consequences . EPA’s goal in this rulemaking should be to fulfill its obligations to protect the nation’s USDWs from both naturallyoccurring and man-made contaminants, while at the same time promoting progress towards successful commercial-scale car bon capture and storage in order to address broader environmental protection concerns.

If EPA is going to address these broade r concerns by establishing a framework for the injection and sequestr ation of CO2 in addition to the incidental storage that occurs in EOR activities, it must address potentially limitless liability under other statutes that EPA administers, including CERCLA [FN40] and RCRA [FN41]. Liability under these statutes w ould act as a strong deterrent to the development of CCS.

Regulated industry has lear ned a great deal in the last 30 years regarding environmental liability. When Congress passed CERCLA, it imposed joint and several liability on landowners, trans porters, and generators of hazardous substances and it made that liability re troactive. Most recently, the Supreme Court, in Massachusetts v. EPA, 549 U.S. 497 (2007), recognized that the Clean Air Act ("CAA"), with its "capacious" defi nition of air polluta nt, could be used to regulate substances (in this case, CO 2) which Congress appeared to not intend to regulate and whose re gulation under many provisions of the CAA (i.e., the NAAQS) is awkward at best. One lesson fr om these statutes and the Courts’ interpretation is that regulated indus try cannot underestimate its potential liability for pollution, irresp ective of its compliance w ith current regulations and irrespective of the magnitude of its role in the waste di sposal process.

Accordingly, as EPA attempts to promote efforts to reduce anthropogenic CO2 emissions, it faces an ever more cautious regulated community. We urge EPA to take determined steps to provide regulato ry clarity as to compliance obligations and potential for liability.

[40] Comprehensive Environmental Respons e, Compensation, and Liability Act

30("CERCLA"), 42 U.S.C. §§ 9601-9675.

[41] Resource Conservation and Recovery Act ("RCRA"), 42 U.S.C. § 6901-6992k.

Individual Response: EPA agrees that overlapping regula tory schemes are undesirable. EPA received many comments regarding the applicability of the RCRA regulations and statute to CO2 streams that are geologically se questered under the final Class VI UIC well requirements. As a result, EPA has decided to initia te a separate proposed rulemaki ng specifically to examine the issue of RCRA applicability to CO2 streams being geologically sequestered, including the possible option of a conditional exemption from the RCRA requirements for CO2 GS in Class VI wells. EPA will consider these comments as pa rt of its development of that proposal. The Agency will consider issues particular to RCRA in the context of that separate rulemaking, and recommends that the commenter read that propose d rule when it is published. The Agency notes that commenters who wish to submit comments on the RCRA proposal will need to do so during the comment period for that rule. Finally, EPA also notes that the final GS rule, which adds new regulations for Class VI wells under the Safe Drinking Water Act (SDWA), is not making any changes to the RCRA regulations.

EPA clarifies that CO2 itself is not listed as a hazardous s ubstance under CERCLA; however, the CO2 stream may contain a listed hazardous s ubstance (such as mercury) or may mobilize substances in the subsurface that could react with ground water to produce listed hazardous substances (such as sulfuric acid). Whether su ch substances may result in CERCLA liability from a sequestration facility depe nds entirely on the composition of the specific CO2 stream and the environmental media in which it is stored (e.g., soil or ground water). CERCLA exempts from liability, under CERCLA section 107, 42 U. S.C. 9607, certain “federally permitted releases” (FPR) as defined in CERCLA, 42 U.S. C. 9601(10). Class VI permits will need to be carefully structured to ensure that they prevent potential releases from the well which are outside the scope of the Class VI permit.

Letter ID: 0215 Comment ID: 24286 Letter Lines: 771 to 852

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

Comment: A. EPA Should Ensure Clarity Regard ing the Possible Coverage of CCS under RCRA

Regarding RCRA, in Section 2.I of the proposal, EPA considers whether the CO2 stream is a hazardous waste. It notes th at the composition of a particular CO2 stream will depend on the source of CO2, the flue gas scrubbing technology, additives, and the CO2 capture technology. EPA concludes that it cannot make a "categorical determination" as to whet her injected CO2 is hazardous under RCRA. Such a determination must be made by owners and operators , however, and a positive finding would mean that the well would be subject to UIC Class I requirements. Thus, EPA’s failure to reso lve this issue could inhibit permitting of wells under the proposed new Class VI regime.

31The Proposed Rule asserts that its desi gn changes are meant to address the mobility and corrosivity caused by long term geologic sequestration of CO2, and not the long term storage of hazardou s wastes. EPA seeks comment on its definition of "carbon dioxide stream" to exclude hazardous wastes:

"Carbon dioxide stream means carbon dioxi de that has been captured from an emission source (e.g., a power plan t), plus incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. This subpart doe s not apply to any carbon dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261."

Using its authority under RCRA, EPA has pr eviously excluded certain substances from coverage under 40 C.F.R. § 261.2. CO2 is not excluded unde r this section, but it is also not specif ically included as a haza rdous substance under 40 C.F.R. § 261.3. Thus, the status of CO2 under RCRA remains a concern.

A determination that CCS activities are subject to RCRA would subject those activities to stringen t handling, storage, and dispos al procedures above what would be required by the Proposed Rule (ex cept with regard to the post-closure period for financial responsibility, which, at 30 years, would be less demanding than the proposed 50 year term for a Cla ss VI well). Such a finding would serve to inhibit the development and adoption of CCS, to the frustration of EPA’s larger efforts to reduce CO2 emissions.

Denbury sets out this basic information only to introduce its specific responses to EPA’s statements and request for comm ent in the proposed rule. RCRA defines solid waste to include "discarded materi al, including solid, liquid, semi-solid, or contained gaseous materi al resulting from industria l . . . operations." 42 U.S.C. § 6903(27). EPA should clarify that injected CO2 in the form of a supercritical fluid does not fall within the definition of a solid waste because it is neither a liquid nor a contained gaseous material. Moreover, any CO2 supply that is acquired for value for us e in EOR or EGR activities should be explicitly excluded as it woul d not be "discarded" at all, but sold for valuable consideration. Were CO2 to not be a solid waste, it would not be subject to RCRA’s waste determination provisions. Only in those cases where the CO2 stream is in the form of a liquid (which it would not be, at pipeline or reservoir conditions) would it be subjec t to these provisions.

Using authority granted by RCR A § 3001, EPA has exempted fr om RCRA’s definition of solid waste certain low-toxicity wastes that exist in high-volumes, including domestic sewage, mining wastes, and certa in nuclear materials, when those materials are covered by other laws. Similarly, EPA should consider its comprehensive regulation of CCS under the UIC permitting provisions to be a sufficient reason to exempt injected supercritical CO2 from RCRA’s coverage as a

32solid waste even where it cannot be sold and used for EOR operations.

Even if EPA decides not to exclude or ex empt injected supercritical CO2 from the definition of solid waste, EPA could and should exempt injected CO2 from the definition of hazardous waste. A hazardous waste under RCRA is a solid waste that, because of its "quantity, concen tration, or physical, chemical, or infectious characteristics" may pose a substantial present or potential hazard to human health or the environment. 42 U.S.C. § 6903(5). Hazardous wastes can be specifically listed by EPA, have hazardous characteristics (such as corrosivity, reactivity, etc), be mixed with a listed waste, or be derived from a listed waste. In the proposed rule, EPA raises th e spectre that the in jection of CO2 in conjunction with hazardous components co uld cause it to be considered a hazardous waste. Because CO2 storage will be closely regulated under the proposed rule, EPA should exempt stored CO2 from the definition of hazardous waste, as it has done for wastes associat ed with the exploration, development, and production of crude oil, natural gas, and geothermal energy. See Regulatory Determination for Oil and Gas and Geothe rmal Exploration, Development, and Production Wastes, 53 Fed. Reg. 25,446 (July 6, 1988).

Even if at present EPA does not foresee bringing an enforcement action for CCS activities, it is important for EPA to exempt CCS activities from RCRA’s definition of solid and hazardous waste to foreclose the availability of a citizen suit under section 7002, brought, perh aps by anti-CCS activists, and the maintenance of which would irreversibly chill CCS projects.

Individual Response: EPA received many comments regardi ng the applicability of the RCRA regulations and statute to CO2 st reams that are geologically seque stered under the final Class VI UIC well requirements. As a result, EPA has deci ded to initiate a sepa rate proposed rulemaking specifically to examine the issue of RCRA appl icability to CO2 streams being geologically sequestered, including the possible option of a conditional exemption from the RCRA requirements for CO2 GS in Class VI wells. EPA will consider these comments as part of its development of that proposal. The Agency will consider issues pa rticular to RCRA in the context of that separate rulemaking, and recommends that the commenter read that proposed rule when it is published. The Agency notes that comment ers who wish to submit comments on the RCRA proposal will need to do so during the comment pe riod for that rule. Finall y, EPA also notes that the final GS rule, which adds ne w regulations for Class VI wells under the Safe Drinking Water Act (SDWA), is not making any changes to the RCRA regulations.

The final GS rule retains the definition of a CO2 stream as pr oposed. The GS regulation applies to injection of CO2 for the purpose of GS, rega rdless of the source of the CO2. It is beyond the scope of the GS rule and the UIC Program’s aut hority to require or set standards for upstream generators of CO2 or purifica tion facilities. For purposes of GS, the UIC program’s authority under the SDWA is limited to ensuring that GS projects are sited, c onstructed, operated, and closed in a manner that protects USDWs. EPA adds that promoti ng the use of GS is outside the scope of the GS rule.

33Letter ID: 0215 Comment ID: 24287 Letter Lines: 854 to 946 ; 1916 to 1918

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment)

Comment: B. EPA Should Exclude Injection and Ge ologic Storage of CO2 from Coverage Under CERCLA

Regarding CERCLA liability, in section II.J of the preamble to the Proposed Rule, EPA notes that the CO2 stream may c ontain hazardous substances or that the CO2 stream could react with groundwater to produce h azardous substances, and concludes that "whether or not there is a ‘hazardous s ubstance’ that may result in CERCLA liability from a sequestration f acility depends enti rely on the makeup of the specific CO2 stream and of the environmental media (e.g., soil, groundwater) in which it is stored." 73 Fed. Reg. at 43,504. EPA notes that CERCLA exempts from liability certain "f ederally permitted releases," including releases in compliance with a UIC perm it under SDWA, and recognizes that Class VI permits will need to be structured to not permit "inappropriate hazardous releases." Id. EPA also requests comment on "particular situations" where there exists the potential for "releases from the well which are outside the scope of the Class VI permit." EPA requests comment on "other considerations associated with the presence of impurities in the CO2 stream related to CERCLA."

Denbury is concerned that any potential fo r CERCLA liability will deter efforts to develop CCS projects. Under CERCLA, private parties or government entities can sue to recover "response costs" as sociated with any "release" from a "facility" of a "hazardous substance." Liability is retroactive, joint and several, and falls upon both current and pa st owners of facilities, and on those who generated or transported those "hazar dous substances." 42 U.S.C. § 9607(a). The broad nature of CERCLA liability ma kes it a vigorous means of addressing sites contaminated with hazardous substa nces, but when applied to CCS would serve to discourage regulated parties who would otherwis e undertake carbon sequestration.

Pure CO2 is non-toxic at low concentrati ons and is not a listed hazardous waste under environmental statutes that CERCLA cross-references in defining "hazardous substances." While it is certainly the case that CO2 is not the type of "hazardous substance" that Congress envi sioned when it enacted CERCLA, the definition that Congress included in th e statute is reminiscent of the "capacious" definition of "air pollutant" that the Suprem e Court gave effect to in Massachusetts v. EPA, 549 U.S. 497 (2007) , to apply provisions of the Clean Air Act to CO2, something that Congress s howed no intent to do when it enacted the Clean Air Act. To avoid a similar out come here, the EPA should define that the injection of CO2 under a Class VI pe rmit constitutes a "federally permitted release."

34EPA’s definition of "federally permitted release" includes "any injection of fluids authorized under Federal underground injection control programs or State programs submitted for Federal approval . . . pursuant to part C of the Safe Drinking Water Act . . ." 42 U.S.C. § 9601(10). CERCLA exempts a federally permitted release from response cost recovery actions. 42 U.S.C. § 9607(j) ("Recovery by any person (including the Un ited States or any State or Indian tribe) for response costs or damages resulting from a federally permitted release shall be pursuant to existing law in lieu of this section.") In the past, EPA has made only minimal efforts to clarify the scope of the federally permitted release exemption (the "FPR ex emption"). In 1988, it stated in the preamble to a proposed rule that would ha ve clarified the FPR exemption that "any underground injection of hazardous substances permitted under a State program . . . or EPA-administered program, is considered federally permitted for purposes of CERCLA notification." Reporti ng Exemptions for Federally Permitted Releases of Hazardous Substances; Proposed Rule, 53 Fed. Reg. 27,268, 27,273 (Jul. 19, 1988). EPA did not finalize that proposal. EPA should use the present proposed rulemaking to reaffirm that an authorized release under the UIC program qualifies for the exemption from CERCL A cleanup liability under section 9607.

To be sure, this would be a narrow exem ption, because EPA has also taken the position that the FPR exemption does not apply to accidental releases. See Guidance on the CERCLA Section 101(10)(H) Federally Permitted Release Definition for Certain Air Emissions, 67 Fed. Reg. 18,899, 18,903 (Apr. 17, 2002). In U.S. v. United Nuclear Corp., EPA took the pos ition that seepage from uranium tailings ponds into groundwater was not part of the permitted activity. 814 F. Supp. 1552 (D.N.M. 1992). In Idaho v. Bunker Hill, the court accepted a state’s claim that CERCLA liability will attach to releases "which we re not expressly permitted in the various permits, which exceeded the limitations established by the permits, or which occurred during a tim e period when there were no permits." 635 F. Supp. 665, 673-74 (D. Idaho 1986). Acco rdingly, EPA could recognize the applicability of th e FPR exemption without signif icantly revising its position on the FPR.

Yet another basis on which to exclude inje cted supercritical CO2 from CERCLA’s ambit is the fact that CO2 is currently a commodity - whether used in the food and beverage industry or for EOR - and will likely remain so for years to come. Denbury currently has contracts to purc hase anthropogenic CO2 from multiple sources. While the price of the CO2 va ries, it has a signifi cant value to Denbury and other EOR operators. As discusse d above, the most realistic path for storage of CO2 over the next several y ears is incidentally in oil and gas bearing formations. Thus, captured anth ropogenic CO2 will be a commodity for purposes of EOR for many years.[FN42] Fu rther, Denbury or other EOR operators may need to access the stored CO2 for use in future EOR operations or for other unforeseen purposes where the use of supercritical substances is necessary and desirable. The proposed rule should thus recognize these factors and clearly classify CO2 as a commodity that is excluded from CE RCLA’s coverage.

35To be sure, EPA does not have the aut hority to protect CCS operations from liability under state statutes and comm on law, and Denbury is not suggesting that EPA attempt to do so in the context of this rulemaking. However, Denbury is asking EPA to use its authority under laws it administers, to reduce the overall risk of exposure for companies enga ging in CCS under a UIC permit regime.

[42] See also Ferguson, et al., supra text accompanying note 34, (estimating potential market for CO2 for EOR pur poses around 7,500 million metric tonnes between now and 2030).

Individual Response: CO2 itself is not listed as a hazardous substance under CERCLA however, the CO2 stream may contain a listed hazardous substance (such as mercury) or may mobilize substances in the subsurface that could react with ground water to produce listed hazardous substances (such as sulf uric acid). Whether such subs tances may result in CERCLA liability from a sequestration f acility depends entirely on the composition of the specific CO2 stream and the environmental media in which it is stored (e.g., soil or ground water). CERCLA exempts from liability, under CERCLA section 107, 42 U.S.C. 9607, certain “federally permitted releases” as defined in CERCLA, 42 U.S.C. 9601(10). Class VI perm its will need to be carefully structured to ensure that they prevent potential releases from the well which are outside the scope of the Class VI permit. EPA is promulgating th is rule under the authority of SDWA. To the extent that the commenter is seeking interpreta tion of CERCLA and its related provisions, such interpretations are outside th e scope of this rulemaking.

The UIC program Director has authority under SDWA §1423 to address potential compliance issues (e.g., potential releases that may endanger USDWs) resulting from injection violations in the unlikely event that a remedi al response is necessary. Although EPA anticipates that the need for emergency or remedial actions at GS sites wi ll be rare, the GS rule requires, at §146.94, that emergency and remedial response plans be deve loped and updated to address such events and that owners or operators demonstr ate that financial resources are set aside to implement the plans if necessary, per §146.85.

EPA clarifies that, while the Administrator re serves the right to promulgate regulations designating additional substances as hazardous under §102 of CERCLA, EPA intends to avoid any potential overlap of SDWA and CERCLA authority through its comprehensive Class VI requirements.

EPA adds that promoting or encouraging the use of GS is outside the scope of the GS rule. Rather, the purpose of the GS regul ation is to ensure that, where deployed, GS is conducted in a manner that protects USDWs from endangerment.

Letter ID: 0215 Comment ID: 24288 Letter Lines: 948 to 967

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82)

Comment: IV. SUGGESTED CHANGES TO LANGUAGE OF PROPOSED RULE

36[In the sections below, the text in CAPS denotes added text.]

A. § 146.82 Required Class VI permit information

This section of the proposed rule sets fo rth the information which the owner or operator must submit to the Director in or der to obtain a Class VI well permit. All of the information specified must be part of the permit application. But some data are not necessary in light of other provisions of the current proposal, and some are not attainable pr ior to well drilling (applicants will not drill the well until it ha s been approved, otherwise they risk drilling an unusable well). Still other data can only be obtained after in jection activities have been initiated. Post-drilling and post-injection data should not be required as part of the application pro cess but instead should be considered confirmatory data that may be submitted af ter they are obtained. In general, the proposed rule should be modified to require submission of only those data which are needed for consideration of the initi al permit application, and only those data that may be reasonably obtained pr ior to commencement of installation and operation of the injection well.

Individual Response: EPA agrees that not all of the information listed at §146.82 of the proposed regulation will be avai lable at the time the owner or operator develops their initial permit application. In response to comments and based on an evaluation of the proposed requirements at §146.82, the Agency revised this subpart so that the final regulation specifies separate requirements for information to be submitted with the permit application and before well construction is approved (at §146.82(a)) and in formation to be submitted before operation of the well is authorized (at §146.82(c)).

EPA believes that this revisi on of §146.82 addresses commenters' concerns regarding the timing of information to be submitted. In addition, section §146.82 in the final rule is similar to the permit application requirements for other inje ction well classes, which could help avoid confusion about how to meet the permitting requirem ents for Class VI wells. The requirements at §146.82(c) for information to be submitted before operation of the well is authorized are very similar to those for Class I wells, with modifi cations and additions th at address the unique challenges and types of data collected for GS wells.

Letter ID: 0215 Comment ID: 24289 Letter Lines: 969 to 991

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82)

Comment: 1. EPA Proposed: §146.82 (f) Maps and stratigraphic cr oss sections indicating the genera l vertical and lateral limits of all USDWs, water wells and springs within the area of review, their positions relative to the injection zone(s) and the directio n of water movement, where known;

37So long as the Applicant proposes to inje ct CO2 below the lowermost USDW, as proposed under the rule, there is no ju stification to require maps and stratigraphic cross sections for the entire extent of those USDWs above the lowermost USDW, although mapping and stra tigraphic cross s ections in the immediate vicinity of the proposed inject ion locations (e.g. where the injection wells will be drilled) should still be required. Data regarding all USDWs in the AoR will likely be costly and/or difficult to collect and, except as noted above, the usefulness of those data seems questionable.

Accordingly, Denbury suggests that subpa ragraph (f) should be modified as follows:

(f) Maps and stratigraph ic cross sections indicating the general vertical and lateral limits of all THE LOWERMOST USDWs
, ALL USDWS IN THE IMMEDIATE VICINITY OF THE PROPOSED INJECTION WELL(S), water wells and springs within the area of review, their positions relative to the injection zone(s) and the direction of water movement, where known;

Individual Response: EPA disagrees with the commenter that there is no justification to require maps and stratigraphic cross secti ons for the entire extent of those USDWs above the lowermost USDW. EPA believes that a thorough understandi ng of the hydrogeologic conditions of all USDWs in the AoR is necessary. EPA clarifies th at §146.82(a)(5) requires, as part of the site characterization and permit application process, that operators submit maps and cross sections indicating the general vertical and lateral limits of all USDWs within the area of review. This information will result in information on and a characterization of the number, location, and depth of USDWs. The Director has the authority to request additional hydrogeologic data or other data on USDWs as well.

Letter ID: 0215 Comment ID: 24290 Letter Lines: 993 to 1008

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82)

Comment: 2. EPA Proposed : §146.82(l) The resu lts of the formation testing program as required in paragraph (j) of this section; (r) All available logging and testing program data on the well required by§ 146.87; (s) A demonstration of mechanical integrity pursuant to § 146.89;

The requirements of subpar ts (l), (r) and (s) of § 146.82 cannot be met until after the well is drilled. For example, subparagraph (l) re ferences (j), formation testing. Clearly formation test ing is a drilling or post completion operation. Similarly, logging and mechanical integrity testing also are drilling or post well completion operations. Because this information will be collected

38post application approval, it should not be required prior to the granting of the Class VI permit.

Denbury suggests that EPA modify § 146.82 to eliminate subparts (l ), (r) and (s) because those data do not belong in and in fact may not be available as part of a permit application.

Individual Response: EPA agrees that not all of the information listed at §146.82 of the proposed regulation will be avai lable at the time the owner or operator develops their initial permit application. In response to comments and based on an evaluation of the proposed requirements at §146.82, the Agency revised this subpart so that the final regulation specifies separate requirements for information to be submitted with the permit application and before well construction is approved (at §146.82(a)) and in formation to be submitted before operation of the well is authorized (at §146.82(c)).

EPA believes that this revisi on of §146.82 addresses commenters' concerns regarding the timing of information to be submitted. In addition, section §146.82 in the final rule is similar to the permit application requirements for other inje ction well classes, which could help avoid confusion about how to meet the permitting requirem ents for Class VI wells. The requirements at §146.82(c) for information to be submitted before operation of the well is authorized are very similar to those for Class I wells, with modifi cations and additions th at address the unique challenges and types of data collected for GS wells.

Letter ID: 0215 Comment ID: 24291 Letter Lines: 1010 to 1028

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 3330 2.2.1.3 Applicability /adequacy of computational models (seeking comment)

Comment: B. §146.84 Area of review and corrective action.

EPA’s proposed rule allows each applicant to define the Area of Review ("AoR") associated with the sequestration proj ect. Denbury has no objection to this flexible approach as it allows the size and shape of the AoR to reflect the unique geology of each CO2 sequestration pr oject. However, under §146.84 (a), to define the AoR, an applicant must use a model capable of considering the physical and chemical properties of all phases of the injected carbon dioxide stream. Denbury is uncertain that there is a model that can satisfy this requirement. Accordingly, Denbury suggests th at the proposed rule be amended as follows:

§146.84 Area of review and corrective action. (a) The area of review is th e region surrounding the geologic sequestration project that may be impacted by the injection activity. The area of review is based on comp utational modeling that, TO THE

39EXTENT PRACTICABLE AND TO THE EXTENT DETERMINED TO BE NECESSARY BY THE DIRECTOR, accounts for the MATERIAL physi cal and chemical properties of all CRITICAL phases of the injected carbon dioxide stream. Individual Response: EPA disagrees that available multiphase models cannot consider the physical and chemical properties of all phases of the injected CO2 stream. Research, as discussed in the preamble to the proposed GS regulat ion and the associated background document "Computational Modeling of Unde rground Injection of Carbon Dioxide for Determination of Area-of-Review and Potential Risk to Undergrou nd Sources of Drinking Water" (cited in the proposed rule preamble as USEPA, 2008d), substa ntiates the modeling re quirements in the GS regulation and indicates that t echnology has advanced to the point that a CO2 injection project can be adequately modeled to support both pr ediction and tracking the movement of the CO2 plume and pressure front. EPA believes the Director should have discretion to evaluate each plan based on current, state of the art modeling scienc e because there are large numbers and types of available models and because advances in the field of geologic modeling continue.

Based on review of all public comments on th e AoR definition at 146.84(a), the Agency has modified it to read as follows: The region surrounding the geologic sequestration project where USDWs may be endangered by the injection activity. The area of review is delineated using computational modeling that accounts for the physi cal and chemical propert ies of all phases of the injected CO2 stream and is based on av ailable site characte rization, monitoring, and operational data.

Letter ID: 0215 Comment ID: 24292 Letter Lines: 1030 to 1037

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

Comment: C. § 146.86 Corrosiveness of the carbon dioxi de stream, and formation fluids.

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

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

40studies 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, EP A 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: 0215 Comment ID: 24293 Letter Lines: 1039 to 1049

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

Comment: 1. EPA Proposed §146.86 (b) Casing and Ce menting of Class VI Wells.(1) (v) Corrosiveness of the carbon dioxid e stream, and formation fluids;

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

Individual Response: EPA clarifies that it is when CO2 is in the presence of water or formation fluids that it can be corrosive to well materials. EPA adds that the corrosive characteristics of the CO2-modified formation fluids can be describe d in a number of technical ways. Corrosiveness should be described by the intera ction between the CO2-modified fluid specific to the project and the well component (e.g., the cement, casing, t ubing or packer) that could be affected.

EPA adds that, with the permit application, th e owner or operator must submit proposed well construction procedures, as specified at §146.82(a)( 12)), that address the specific drilling and injection environment and the ch emical and physical na ture of the CO2 in jected stream. The Director will evaluate the appropriateness of the proposed construction based on site-specific information about the injection project, as specified at §146.86(b)(1). In making this determination, the Director will also have th e large array of geologic, geochemical, and hydrologic data on the site that the owner or opera tor must submit to meet the permit application requirements at §146.82(a). EPA adds that during the permit application process, the owner or operator and the permitting authority should work toge ther to determine the specific tests that are

41appropriate, based on the site -specific circumstances.

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

Letter ID: 0215 Comment ID: 24294 Letter Lines: 1051 to 1090 ; 1920 to 1921

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

Comment: 2. EPA Proposed §146.86 (b) Casing and Ce menting of Class VI Wells. (3) At least one long string casing, us ing a sufficient number of centralizers, must extend to the inje ction zone and must be cemented by circulating cement to the surface in one or more stages. * * * (5) Cement and cement additives must be compatible with the carbon dioxide stream and form ation fluids and of su fficient quality and quantity to maintain integrity ove r the design life of the geologic sequestration project. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channe ls to ensure that USDWs are not endangered.

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

Denbury suggests an alternative that protec ts USDWs, but at a reasonable cost. Rather than require cementing of the long string casing to the surface, the proposed rule should require cement and cem ent additives to be compatible with the carbon dioxide stream and formation flui ds that cover the in jection zone and the confining zone, and then require sta ndard (API, ASTM International, or

42comparable standards) industry cements to a certain distance above the confining zone. This would place cements that may re quire special additives at the point where USDWs are most effectively protec ted from the mixture of carbon dioxide and formation fluids that could produce carbonic acid.

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

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

The final cost analysis supporti ng the GS Rule includes cementi ng costs of $1.20 per foot lengthinch diameter plus 25% of to tal cementing costs for use of corrosion-resistant cement. For a representative deep saline injection well used in the cost analysis, this translates to a total cementing cost of $406,500 per injection well, repres enting an incremental co st of approximately 305,000 over baseline costs. This unit cost is in line with estimates provided by the commenter (actual costs are driven by well-specific characte ristics). While the rule requirements necessitate these additional costs, the requirements are guided by the necessity to address the unique challenges posed by CO2 injecti on (including large injection vol umes, the relative buoyancy of CO2, its corrosivity in the presence of water, th e potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations) as they protect USDWs from endangerment.

Letter ID: 0215 Comment ID: 24295 Letter Lines: 1092 to 1110

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)

Comment: Denbury suggests the following revision:

§146.86 (b) Casing and Cementing of Cla ss VI Wells. (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection z one and must be cemented by circulating cement to the surface INJECTION ZONE AND CONFINING ZONE AND AN AUTHORIZED DISTANCE ABOVE THE CO NFINING ZONE, SUBMITTED BY THE PERMITTEE AND APPROVED BY THE DIRECTOR in one or more stages. * * * (5) TO PROTECT USDWS, C cement and cement additives must be compatible with the carbon dioxide st ream and formation fluids and of sufficient quality and quantity to maintain integrity over the

43design OPERATING life of the WELL geologic sequestration project MUST BE USED ACROSS THE INJE CTION ZONE AND CONFINING ZONE. The integrity and location of the ce ment shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

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 have long life-spans in comparison to other types of deep injection wells. Not only must Class VI wells be able to function safely and properly over the lifespan of the GS project, but they must be 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 the post-injec tion site care period and beyond. While th e risk profile of a GS site will decrease following cessation of in jection, EPA believes that Class VI wells must be designed to protect USDWs from endangerment for the life of the project. Furthermore, rigorous casing and cementing help ensure that the Class VI well will not serve as a conduit fo r movement of fluids associated with future injection operations.

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

Letter ID: 0215 Comment ID: 24296 Letter Lines: 1112 to 1120

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)

Comment: D. § 146.87 Logging, sampling, and testing prior to injection well operation.

EPA’s proposed § 146.87 delineates the info rmation a permittee must collect during the drilling and cons truction of a Class VI well, prior to actual injection activities. Although the proposed rule generally allows the Director to approve alternative met hods that provide equivalent or better information, it is not clear that the Director can utili ze that regulatory flexibility to waive unnecessary, duplicative testing which the proposed rule requires in several subparagraphs.

Individual Response: EPA disagrees that any tests should be waived. EPA believes that all logs, surveys, and tests listed at §146.87 are necessary to verify inform ation about the injection and confining zones and ensure th at the well is being drilled and cased as approved, and has mechanical integrity. This information is needed to demonstrate that the well can be operated and tested in a manner that protects USDWs fr om endangerment. While the tests do provide information on some of the same items, each test provides unique pieces of information that build on each other and allow for interpretations not possible with a si ngle test. Existing lithologic and geologic information may lack the de tails needed for site-specific well design and the geology needed to support protecti on of USDWs from endangerment.

44Letter ID: 0215 Comment ID: 24297 Letter Lines: 1122 to 1147

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)

Comment: 1. EPA Proposed § 146.87 (a)(2) Before and upon insta llation of the surface casing:... (ii) A cement bond and variable densit y log, and a temperature log after the casing is set and cemented.

The requirements in §146.87(a )(2)(ii) to secure and submit specified logs before, upon and after surface casing inst allation is excessive. The proposed rule fails to provide a sufficient just ification for requiring a cement bond and variable density log before and upon inst allation of the long string casing, and requiring a temperature log after the cas ing is set and cemented. Temperature logs are seldom used in the dri lling industry to determine cement characteristics as they do not provide useful data rega rding the bonding of cement. The rules should be modified to allow the permittee to select between the specified logs and any other loggi ng tool approved by th e Director as follows:

§146.87(a)(2)(ii) A cement bond and vari able density log OR OTHER APPROVED TOOL, and OR a temperature log after the casing is set and cemented. [see § 146.12(d)(2)(i)( B) Criteria and Standards applicable to Class I nonhazardous wells: Construction Requirements.] * * * (5) Any alternative methods that provide equivalent or better information and that are required of a nd/or approved of by the Director. THE DIRECTOR MAY WAIVE ANY LOG OR TEST SPECIFIED IN THIS SUBPARAGRAPH.

Individual Response: Cement bond, variable density, and te mperature logs are required by §146.87(a)(2) upon installation of the surface casi ng. EPA disagrees that the surface casing logging requirements are excessive. Evaluation of all logs, surveys, and tests listed in the rule will provide detailed information on the parts of the well that will penetrate the lowermost USDW and provide information on the quality of the cement seal with surrounding formations in order to ensure protection of USDWs from endangerment.

As described above, EPA disagrees that any tests should be waiv ed. While the tests do provide information on some of the same items, the test s provide unique pieces of information which enhance each other and allow for interpretations not possible with a single test. For example, a variable density log can detect microannuli, fractures, and formation effects. Temperature logs can detect fluid or gas flow through channels that cannot be detected by either of the other tests.

45Letter ID: 0215 Comment ID: 24298 Letter Lines: 1149 to 1173

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)

Comment: 2. EPA Proposed §146.87 (a)( (3) Before and upon installation of the long string casing: (i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any other logs the Director requires for the given geolo gy before the casing is installed; and

Once again, the proposed rule requires tes ting that would be of little benefit in protecting USDWs, but would impose significant costs on operators. For example, Denbury sees no basis to run a fracture finder log in every well. Fracture finder logs will only see mi nor fractures within the individual formations. The log does not provide information on whether these minor fractures can act as conduits between the injection zone and confining zone. To avoid unnecessary data collection and s ubmittal, the rules should allow the applicant to propose and justify a logg ing suite based on the reservoir and geology associated with the particular CO2 project. The Director of course should be allowed to approve, or recommend revisions to the proposed suite. This would avoid mandating unneeded testing. De nbury suggests the following revised rule, incorporating this proposed change:

§146.87 (a)( (3) Before and upon installa tion of the long string casing: (i) Resistivity, spontaneous potenti al, porosity, caliper, gamma ray, fracture finder logs, and any other OR ANY SUITE OF LOGS SUBMITTED BY THE PERMI TTEE AND APPROVED BY logs the Director BEFORE THE CASING IS INSTALLED requires for CONSIDERING the given geology before the casing is installed ; and

Individual Response: EPA believes that a minimum suite of logs and tests is necessary at all Class VI wells. All logs, surveys, and test s listed at §146.87(a) are necessary to verify information about the injection and confining zone s and ensure that the well is being drilled and cased as approved and has mechanical integrity.

EPA notes that owners or operators will descri be in their permit applications how they will construct and test the well, and will also subm it site-specific information about the subsurface geology. The Director will evaluate the proposed logging activities al ong with site-specific geologic information to identify geologic data of interest.

EPA adds that, should alternative methods be show n to provide equivalent or better information or if site-specific conditions and risk factors dictate that other l ogs are necessary, the Director has the discretion at §146.87(a)(5) to require further logs and tests if necessary and to approve alternative methods that provide eq uivalent or better information.

46Letter ID: 0215 Comment ID: 24299 Letter Lines: 1178 to 1192

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)

Comment: The proposed rule also requires unnecessa ry and duplicative logging with respect to the long-string casing.

3. EPA Proposed §146.87(a)( (3) Before a nd upon installation of the long string casing: (ii) A cement bond a nd variable density log, and a temperature log after the cas ing is set and cemented.

Denbury suggests that the logging options it recommends with respect to surface casing also apply for the long-string casing. Thus, the proposed ru le should be revised as follows:

§146.87(a)(3)(ii) A cement bond and vari able density log OR OTHER APPROVED TOOL, and OR a temperature log after the casing is set and cemented. [see § 146.12(d)(2)(ii)(C ) Criteria and Standards applicable to Class I nonhazardous wells: Construction Requirements.]

Individual Response: EPA disagrees that the requirements for logging of the long-string casing at §146.87(a)(3)(ii) are unnecessary. While the tests do provide information on some of the same items, the tests provide unique pieces of info rmation which enhance each other and allow for interpretations not possible with a single test. For example, a va riable density log can detect microannuli, fractures, and formation effects. Te mperature logs can dete ct fluid or gas flow through channels that cannot be detect ed by either of the other tests.

Determining the quality of the cementing of the long-string casing is esse ntial to the protection of USDWs from endangerment. EPA adds that, should alternative methods be shown to provide equivalent or better informati on, the Director may allow such alternatives under §146.87(a)(5).

Letter ID: 0215 Comment ID: 24300 Letter Lines: 1194 to 1231

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)

Comment: 4. EPA Proposed §146.87(b) The owner or operator must take and submit to the Director whole cores or sidewall cores of the injection zone and confining system and formation fluid sa mples from the injection zone(s). The Director may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core othe r formations in the borehole.

47Denbury opposes the requirement to collect cores from more th an one (1) well within a CO2 project. As a practical matter, the majority of the important physical and geophysical properties of th e injection reservoir, including the particular attributes of the confining formations can and are required to be evaluated from logs and other scientific, reliable measures. A "whole core," as specified in §146.87(b) is only a very sma ll sample of the attributes of a reservoir and a sidewall core, an even smaller sample. The former is very expensive to collect, and the latter often not available. Neither is essential given the vast amount of data otherwise required, and multiple samples, as proposed by the rule, are not reasonab le. The unreasonablene ss of the whole core, sidewall core and extra core sampli ng is evident upon consideration of the sheer volume of physical evidence that th is provision alone may produce. For example, in Texas there are over 5000 exis ting Class II CO2 injection wells. If a small fraction of these wells are convert ed to Class VI CO2 injection wells following the completion of production act ivities, there wi ll be a large universe of cuttings. Where will the regul atory agency store this magnitude of cuttings? This may become a particular problem given the total number of CO2 sequestration projects that may be proposed.

Denbury suggests the following:

§146.87(b) AT THE SPECIFIC REQUEST OF THE DIRECTOR AND ONLY WHERE CORE RETRIEVAL IS POSSIBLE, TT he owner or operator must take and submit to the Director A whole cores or sidewall cores of the injection zone and confining system and formati on fluid samples from the injection zone(s). The Direc tor may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of co nditions at the well. The Director may require the owner or operator to core other formations in the borehole.

Individual Response: EPA clarifies that §146.87(b) allows information on cores from nearby wells to be submitted if the owner or operator can demonstrate that core retrieval is not possible and that cores from nearby wells are representa tive of conditions at the Class VI well. EPA clarifies that, at a minimum, repor ts on cores of injection zones, confining zones, and samples of formation fluids must be submitted. Section 146.87(b) gives the Director authority to require the owner or operator to core other formations in the borehole if necessary to provide sufficient geologic information to verify that the site is suitable for GS.

EPA clarifies that it is not the Ag ency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or si dewall cores of the injec tion zone and confining system and formation fluid samples from the injec tion zone(s), and must submit to the Director a detailed report prepared by a l og analyst that includes: well lo g analyses (including well logs), core analyses, and formation fluid sample information...."

48Letter ID: 0215 Comment ID: 24301 Letter Lines: 1233 to 1254

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)

Comment: 5. EPA Proposed §146.87(d) At a minimum, the owner or operator must determine or calculate the follo wing information concerning the injection and confining zone(s): (1) Fracture pressure; (2) Other physical and chemical characteristics of the injection and confining zones; and (3) Physical and chemical characteristic s of the formation fluids in the injection zone.

Subparagraph (d) of §146.87 provides permittees with a generic list of data that is required regarding the injection and confining zone. Fractu re pressure is specified. Under the circumstances, fracture pressure should only be calculated, rather than "determined" as any de termination based on techniques beyond mathematical calculation will require co ring or perforation of the casing, potentially decreasing the mechanical inte grity of the well an d running directly counter to the objective of the proposed rules. With re spect to other generic data EPA seeks regarding the injection a nd confining zones, the proposed rule does not to provide sufficient guidance to the permittee on the scope of data required on the formation fluids and reservoir zones. Denbury requests clarification and specifics both with re spect to the nature and type of "physical and chemical characteristics" EPA expects a permittee to submit in response to the requirement s of 146.87(d) (2) & (3).

Individual Response: EPA disagrees that the wording at §146.87(d) would lead the owner or operator to employ destructive testing methods for determina tion of fracture pressure. The wording "determined or calculate d" allows for calculations to be performed based on nondestructive methods. EPA is developing guidance on monitoring and testing that will describe recommended tests and procedures to assist ow ners/operators and Dire ctors in evaluating the requirements for pre-operational logging and testing under §146.87, including providing information on the physical and chemical characte ristics of the injecti on and confining zones. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0215 Comment ID: 24302 Letter Lines: 1256 to 1277

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)

Comment: 6. EPA Proposed §146.87(f) The owner or operator must provide the Director with the opportunity to witn ess all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director 30 days prior to c onducting the first test and submit

49any changes to the schedule 30 days prior to the next scheduled test.

The agency requires the submission of a proposed logging and te sting schedule at least 30 days in advance of those pro posed activities. Although a logging and testing schedule certainly can be designe d 30 or more days in advance, the actual date that logging is performed is usually available only 24 to 48 hours in advance of actual logging operations. A mandatory 30 day notice is simply not practical for logging and testing. Denbury as ks that notice requirements in this subpart be adjusted to take into acco unt the practical limitations experienced routinely in field operations . Suggested revised language is set forth below.

§146.87(f) The owner or operator must provide the Director with the opportunity to witness all logging an d testing by this subpart. The owner or operator must submit a PROPOS ED schedule of such activities to the Director AT LEAST 30 days prio r to conducting the first test and submit NOTICE AT LEAST 24 HOURS IN ADVANCE OF THE CONDUCT OF ANY ACTUAL LOGGING AND TESTING. any changes to the schedule 30 days prior to th e next scheduled test.

Individual Response: EPA disagrees that the 30-day notif ication requirement is unreasonable. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide mu ch needed field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ab ility to be involved.

Letter ID: 0215 Comment ID: 24303 Letter Lines: 1279 to 1306

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 4100 2.4.1 Injection parameters

Comment: E. § 146.88 Injection well operating requirements.

1. EPA Proposed §146.88(c) The owner or operator must fill the annulus between the tubing and the long string casing with a non-corrosive fluid approved by the Director. The owner or operator must maintain on the annulus a pressure that exceeds the op erating injection pressure, unless the Director determines that such requirement might harm the integrity of the well.

EPA’s suggested Mechanical In tegrity ("MI") rule to maintain pressure on the annulus exceeding the operat ing injection pressure will , in most cases, result in an exceedance of the bur st pressure of the casi ng. If the operator is required to maintain pressure on the annulus at a rate that is greater than the injection pressure (as indicated in EPA proposed §146.88(c)), monitoring the annulus pressure may not be an accurate indicator of mechanical integrity. The

50EPA appears to recognize th is likelihood and thus allows the Director to waive the requirement. However, the rule sh ould not require a questionable practice and then permit its waiver. Rather, the practice should only be required if the Director makes a determination that the conduct of the test will NOT cause a problem. The suggested revisi on is encapsulated below:

(c) The owner or operator must fill the annulus between the tubing and the long string casing with a non-co rrosive fluid approved by the Director. IF THE DIRECTOR DETERMIN ES THAT SUCH REQUIREMENT WILL NOT HARM THE INTEGRITY OF THE WELL, Tt he owner or operator must maintain A POSITIVE PRESSURE on the annulus a pressure that exceeds the operating injection pressure. ., unle ss the Director determines that such requirement might harm the integrity of the well.

Individual Response: EPA disagrees that maintaining annulus pressures that exceed the injection pressure would cause bursting of the casing. A properly designed well that takes into account the geologic and geomechan ical properties of the site based on information collected under §146.82 and meets the constr uction requirements at §146.86 woul d be able to maintain integrity if the annulus pressure were reasonably higher than injection pressure.

The purpose of continuous pressu re monitoring (to demonstrate in ternal MI) is to demonstrate that no pressure changes are occurring, because a drop in pressure on th e annulus provides an early indication that attention is needed to prevent a loss of MI or unacceptable fluid movement. EPA believes that any change in the pressure on the annulus between tubing and long stem casing, regardless of what the annulus pressure is relative to injection pr essure, can indicate a leak.

The GS rule, at §146.88(c), allows the Director to make exceptions if th e Director determines that such a requirement might ha rm the integrity of the well. The final regulation at §146.88(c) requires that the owner or operator must mainta in on the annulus a pressure that exceeds the operating injection pressure, unles s the Director determines that such requirement might harm the integrity of the we ll or endanger a USDW.

Letter ID: 0215 Comment ID: 24304 Letter Lines: 1308 to 1332

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

Comment: 2. EPA Proposed §146.88(e) The owner or operator must install and use continuous recording devices to mon itor: The injection pressure; the rate, volume, and temperature of the carbon dioxide stream; and the pressure on the annulus between the tubing and the long string casing and annulus fluid volume; and must in stall and use alarms and automatic down-hole shut-off systems, designed to alert the operator and shut-in the well when operating parameters such as annulus pressure, injection rate or other parameters approved by the Director diverge beyond

51permitted ranges and/or gradients specified in the permit;

The installation and use of automatic down-hole shut-off systems creates a potential avenue for leakage and is unn ecessary on land-based onshore systems. Down-hole shutoff systems, more commonly used in off-shore operations, serve to shut in the well and prevent reservoir fl uids from exiting the wellbore. They are used in off-shore operations because of the risk of damage to the wellhead from atmospheric or anthropogenic phe nomenon, such as a hurricane causing extensive platform damage or a ship collid ing with a platform. But in an onshore injection system, a down-hole shut-off sy stem will not determine or deter leakage of fluids in the wellbore and therefore is not effective in protecting USDWs. Also, the likelihood of damage to an onshore wellhead is extremely remote. The greater risk in a Class VI onshore operation is that the mechanics of the down-hole shut-off system will be compromised or malfunction. Such a malfunction would require removal of the tubing and shut-off system equipment, thereby creating a potential unwanted migration path. The use of automatic downhole shut-off systems should be li mited to off-shore operations.

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 a 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.

52Letter ID: 0215 Comment ID: 24305 Letter Lines: 1334 to 1349

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 4520 2.5.1 Continuous internal mechani cal integrity monitoring (seeking comment)

Comment: Furthermore, the requirement to continuously monitor the annulus fluid volume is impractical, because it does not provide a ny meaningful data regarding potential problems with the operation of the well. Requiring the continuous monitoring of the amount of annulus fluid added during operations is more practical and will reveal potential leakage paths. De nbury recommends the following:

§146.88(e) The owner or operator must install and use continuous recording devices to monitor: The in jection pressure; the rate, volume, and temperature of the carbon dioxid e stream; and the pressure on the annulus between the tubing and the l ong string casing and THE VOLUME OF annulus fluid added to the annulus volume ; and the owner or operator must install and use alarms and automatic down

- hole shut-off systems, designed to alert the opera tor and shut- in off the well when operating parameters such as annulus pressure, injection rate or other parameters approved by the Director diverge beyond permitted ranges and/or gradients specified in the permit. IF THE

Individual Response: EPA believes that monitoring of annulus fluid volume is an important method for verifying that the well system is in tact and is necessary for monitoring annulus pressure. While this requirement has, until 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 a nnulus fluid volume may not be appropriate. EPA believes that knowing annulus fluid volume as required at §146.88(e) is a necessary component of monitoring well mechanical integrity, but al so believes that knowing the annulus fluid volume added is sufficient to meet the intent of the re quirement. The final GS rule requires that owners or operators use continuous reco rding devices to monitor injecti on pressure, rate, and volume, as well as the pressure on the annulus between the tubing and the long string casing. It also modifies the requirement in the proposed rule to continuously monitor annulus fluid volume; it now requires recording of annulus flui d volume added. See §§146.88(e); 146.89(b); and 146.90 (b).

Letter ID: 0215 Comment ID: 24306 Letter Lines: 1350 to 1360

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment)

Comment: OPERATION INVOLVES OFF-SHORE INJECTION, THE OWNER OR

53OPERATOR MUST INSTALL AND USE ALARMS AND AUTOMATIC DOWN-HOLE SHUT-OFF SYSTEMS, DESIGNED TO ALERT THE OPERATOR AND SHUT-IN THE WELL IF THE WELLHEAD IS DAMAGED OR WHEN OPERATING PARAM ETERS SUCH AS ANNULUS PRESSURE, INJECTION RATE OR OTHER PARAMETERS APPROVED BY THE DIRECTOR DIVERGE BEYOND PERMITTED RANGES AND/OR GRADIENTS SPECIFIED IN THE PERMIT;

(f) If aN down

- hole automatic shutdown is tr iggered or a loss of mechanical integrity is discovere d, the owner of operator must immediately investigate and identify as expeditiously as possible the cause of the shutoff.

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.

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.

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 protection of USDWs, human health, and the environment.

Letter ID: 0215 Comment ID: 24307 Letter Lines: 1365 to 1386

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment)

Comment: F. § 146.89 Mechanical integrity.

1. EPA Proposed §146.89(c) At least once per year, the owner or operator must use one of the following methods to determine the absence of significant fluid movement under para graph (a)(2) of this section:

54(3) A casing inspection log, if required by the Director.

Among the test protocols prescribed by th e proposed rule to confirm lack of significant fluid movement is a casing inspection log. Although this log is optional, it may be required by the Dir ector. Conducting a casi ng inspection log will require the tubing to be pulled from a well, and that in turn substantially increases the possibility of a well contro l event (that is a loss of control over well operation). Accordingly, the t echnique should only be mandated when other testing methodologies are unavaila ble. Denbury suggests the following edit:

§146.89(c) At least once per year, the ow ner or operator must use one of the following methods to determine the absence of si gnificant fluid movement under paragraph (a )(2) of this section: (3) A casing inspection log, if A TRAC ER SURVEY OR A TEMPERATURE OR NOISE LOG CANNOT BE OBTAINED AND A CASING INSPECTION LOG IS THUS required by the Director.

Individual Response: EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind the casing, but clarifies that it is appropriate for determining the presence or absence of corrosion of the long-st ring casing, and is required if the Director determines that it is necessary based on site-s pecific information. EPA has revised the final GS rule to require that the frequency of the casing in spection log be specified in the approved testing and monitoring plan at §146.89(d).

Letter ID: 0215 Comment ID: 24308 Letter Lines: 1388 to 1399

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 4620 2.6.2 Injectate monitoring

Comment: G. § 146.90 Testing and monitoring requirements.

1. EPA Proposed §146.90(b) Installati on and use, excep t during well workovers as defined in § 146.86(d), of continuous recording devices to monitor injection pressure , rate and volume; the pr essure on the annulus between the tubing and the long string casing; and the annulus fluid volume;

Consistent with our comment regarding proposed § 146.88(e) in Section 5 above, Denbury is unaware of a methodology to m onitor the actual volume of annular fluid in the annulus on a continuous basis, and thus seeks agency clarification on this portion of the proposed rule.

Individual Response: EPA believes that knowing annulus fluid volume, as required at §146.88(e), is a necessary component of monitoring well mechanical integrity, but believes that monitoring the annulus fluid volume added is su fficient to meet the intent of continuous

55monitoring of the pressure on th e annulus. The final GS rule at §146.90 (b) requires that owners or operators use continuous reco rding devices to monitor injec tion pressure, rate, and volume; the pressure on the annulus between the tubing an d the long string casing; and the annulus fluid volume added.

Letter ID: 0215 Comment ID: 24309 Letter Lines: 1401 to 1435 ; 1923 to 1934

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 4630 2.6.3 Corrosion monitoring

Comment: 2. EPA Proposed §146.90(c) Corrosion m onitoring of the well materials for loss of mass, thickness, cracki ng, pitting and other signs of corrosion must be performed on a quarterl y basis to ensure that the well components meet the minimum standa rds for material strength and performance set forth in § 146.86(b) by: (1) Placing coupons of the well constr uction materials in contact with the carbon dioxide stream; or (2) Routing the carbon dioxide stream through a loop constructed with the material used in the well; or (3) Using an alternative met hod approved by the Director;

Denbury believes the requirements in EPA proposed §146.90(c) related to corrosion monitoring are inapplicable. In the vast majority of cases, the CO2 will be transported to the injection site through pipelines, will be dehydrated prior to transportation a nd therefore when injected it will be noncorrosive.[FN44] In those instances, the test methods described in § 146.90(c) (1) and (c)(2) (except of c ourse alternatives approved by the Director) will not provide meaningful information regarding the mechanical inte grity of down-hole casing, tubing and other equipment because the CO2 will simply not be corrosive at the surface. Consequently, to have any relevance such requirements should be reserved for situations where water saturated CO2 is being injected.

§146.90(c) Corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting and other signs of corrosion must be performed on a quarterly basis to ensure that the well components THAT CONTACT WATER SA TURATED CARBON DIOXIDE STREAMS meet the minimum standards for material strength and performance set forth in § 146.86(b) by: (1) Placing coupons of the well cons truction materials in contact with the carbon dioxide stream; or (2) Routing the carbon dioxide stream through a loop constructed with the ma terial used in the well; or (3) Using an alternative method approve d by the Director. THE REQUIREMENTS OF THIS SUBPART ARE WAIVED WHEN THE CARBON DIOXIDE STREAM IS DEHYDRATED

56TO MEET PIPELINE SPECIFICATIONS.

[44] For evidence on CO2 corrosiveness in the absence of fr ee water see Don Duttlinger, "Enhanced Recovery Intertwine s Naturally With CO2 Sequestration," Tech Connections Column, American Oil a nd Gas Reporter (January 2004), available at http://www.pttc.org/aogr_columns_a rchived/aogrcojan04.htm (From the processing/injection standpoint, CO2 is noncorrosive as long as it is dry. Proving that point, Kinder Morgan has hydr o-tested the 32-yea r-old CRC Pipeline built in 1971 to transport CO 2. Only one minor failure occurred. After testing, the line was rated for 2,025 psi maximum operating pressure, which established a 200 psi increase over most recent ratings); see also J. Layne, "Results of the Hydrotest of the 30-year old Canyon R eef Carriers CO2 Pipeline," 2003 CO2 Flooding Conference, University of Texas of the Permian Basin's Center for Energy and Economic Diversification, Midland,Texas (December 11-12, 2003).

Individual Response: EPA disagrees that corrosion mon itoring is unnecessary or excessive. CO2 in the presence of water (including water with NOx, SOx, and H2S impurities) can be corrosive to well materials and cements. Thus, although a CO2 stream may be dry, the potential for corrosion of well materials down-hole, where the injectate can potentially mix with water in the target formation, must be c onsidered. EPA believes that the te sting methods specified in the rule are appropriate and have been used successf ully by Class I hazardous waste injection well owners or operators.

Several laboratory studies a nd a limited number of field studies have investigated and characterized the effects of carbonic acid on well materials. La boratory studies (e.g., Kutchko et al., 2007; Kutchko et al., 2008) cons istently identify al terations (typically carbonation) of cement as the result of interactions betw een cement and CO2-saturated brine.

Currently, there are only a few analyses of cemen t from wells that have been in prolonged contact with CO2 in actual fiel d (down-hole) conditions. Evaluati on of cement from a well at the Scurry Area Canyon Reef Operator s Committee (SACROC) site s howed alteration, but did not show degradation that compromise d the structural integrity of th e cement (Carey et al., 2007). In another study, cement samples were collected and analyzed from a CO2 production well in a natural CO2 reservoir in Colorado exposed to a CO2-water down-hole environment for 30 years (Crow et al., 2008). The study found evidence of reaction between the CO2-rich water and the
cement.

Oil industry research also addre sses the effects of corrosion of st eel tubing and pipes. Lopez et al. (2003) noted that 60 percent of oilfield failures are re lated to the effects of carbonic acid from produced brines on carbon and low alloy steels.

Laboratory investigation of cement alteration/de gradation is an ongoing re search area. Few fieldbased studies have been completed to date. The laboratory and field stud ies currently available suggest that corrosion problems can be managed; however, there is no t a large enough body of research to rule out potentia l corrosion problems of steel co mponents of injection wells. The IPCC (2005) report on carbon dioxide capture an d storage reviewed oil and gas industry

57experience with gas injection we lls, close industry analogues to CO2 injection wells. The report stated that while the design of CO2 injection we lls will be very similar to gas injection wells, most down-hole components of the CO2 injecti on wells will “need to be upgraded for higher pressure ratings and corrosion resistance.” Give n the pressure and corrosion considerations, anticipated long lifespan of a GS well and the difficulties that would be associated with a corrosion-related well failure, EPA believes th at corrosion monitoring in the down-hole environment is justified. For thes e reasons, the final ru le requires quarterly corrosion monitoring (at §146.90(c)). See the final rule and preamble fo r further discussion on EPA's final approach.

Letter ID: 0215 Comment ID: 24310 Letter Lines: 1437 to 1443

Comment Code: 4640 2.6.4 Pressure fall-off testing (seeking comment)

Comment: 3. EPA Proposed §146.90(f) A pressure fa ll-off test at least once every five years unless more frequent test ing is required by the Director based on site specific information;

The scope of this proposed requirement is not clear. Does the EPA proposal require the submittal of the actual data, or merely an analysis of the pressure fall-off test?

Individual Response: EPA expects that the Director woul d request an electronic copy of the data in addition to an analysis report completed by the owner or operator. This would afford the Director the opportunity to review the data and verify that the analysis is accurate. EPA also expects that the details of what information must be submitted would be described in the testing and monitoring procedures in the Class VI permit.

Letter ID: 0215 Comment ID: 24311 Letter Lines: 1445 to 1464

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

Comment: 4. EPA Proposed §146.90(i) Any additiona l monitoring, as required by the Director, necessary to support, upgr ade, and improve computational modeling of the area of review eval uation required under § 146.84(b) and to determine compliance with standards under 40 CFR 144.12

This section effectively proposes a "catch all" to allow the Di rector undefined discretion to order unlimited and unspecifi ed additional monitoring to improve modeling and ensure compliance. Vesting the Director with such additional undefined discretionary authority increases the regulatory risks of the Class VI permitting process and accordingly increases costs. In the event that experience implementing the proposed rule requires some future revisions to include additional monitoring requirements, such changes should be proposed and adopted

58through appropriate rulemaking procedures and based on an adequate factual and scientific record. However, adopting anopen-ended power to require "any" additional monitoring, at this early stag e, undermines the purpose of providing a defined set of rules that members of the public may evaluate prior to making the large investments that will be involved in Class VI projects. Such uncertainty can only tend to increase co sts, creating a barrier to capital formation and discouraging geologic sequestration. Accordingly, Denbury recommends deleting this section.

Individual Response: EPA does not believe that UIC Di rectors should have undefined discretion when ordering additional monitori ng requirements. EPA believes that, given the variety of site-specific circumstances that may be encountered at GS sites, it is reasonable to afford the Director discretion only when addi tional testing and mon itoring requirements are required to ensure the protection of USDWs.

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 pre ssure front, and soil gas and su rface air monitoring which may be required by the UIC Director for specific GS projects. The guidance will discuss how the Director may exercise any discretion. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0215 Comment ID: 24312 Letter Lines: 1466 to 1480

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 5100 2.8.1 Injection well plugging activ ities (seeking comment) (40 CFR 146.92)

Comment: H. § 146.92 Injection well plugging.

1. EPA Proposed §146.92 (b) Well Plugging Plan. (5) The type and grade and quantity of material to be used in plugging. The material must be compatible with the carbon dioxide stream;

The proposed regulation requires the wellbor e to be flushed prior to plugging and thus it is unnecessary to use cemen t "compatible with the carbon dioxide stream." In the absence of water, CO2 is non-corrosive and compatible with conventional cements (see discussion under Comment #G). Accordingly, the rule should be revised as follows:

§146.92 (b) Well Plugging Plan. (5) The t ype and grade and quantity of material to be used in plugging. T he material must be compatible with the carbon dioxide stream;

59Individual Response: EPA believes, considering the potentia lly corrosive nature of CO2 when it is in contact with water, that the requirement that the material must be compatible with the CO2 stream is appropriate. The final rule retain s this requirement because CO2 and water will be present in the subsurface.

Letter ID: 0215 Comment ID: 24313 Letter Lines: 1482 to 1619 ; 1936 to 1936

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93)

Comment: I. § 146.93 Post-injection site care and site closure.

The proposed rule establishes a 50 year default period for pos t-injection site care. There is, however, no factual or scie ntific basis for such an extensive period. Under EPA’s Resource Conservation an d Recovery Act rules, which regulate the disposal of hazardous wastes, po st closure care is limited to 30 years.[FN45] Defaulting to an excessive ly long period will increase costs and introduce greater regulatory uncertainty, which will discourage capital formation around CO2 sequestration. A more pr udent regulatory approach is to set a minimum period for site care, ten years, with allowance for the Director to extend the period if facts and circumst ances warrant a longer post-injection site care period.

Additionally, the proposed ru le’s 50 year default pos t injection site care period, is an illusory deadline, as it is not self-executing. Under the rules, post injection site care must continue indefinitely until the Director authorizes closure. The closure approval process could take years, even decades, as the Director has no regulatory incen tive to act on any post injection site care report. Meanwhile, a permittee may be required to continue unnecessary and expensive monitoring and reporting indefinitely.

Denbury suggests that the post-injection s ite care rules be reconfigured to require a more limited mandatory post-i njection site care timeframe, and to allow for closure at the end of that pe riod unless the Director affirmatively acts to extend the post-injection site ca re period. These changes are contained in the suggested text below:

§ 146.93 Post-injection site car e and site closure. (a) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan for post-injectio n site care and site closure that meets the requirements of paragraph (a)(2) of this section and is acceptable to the Director. (1) The owner or operator must submit the post-injection site care and site closure plan as a part of the permit app lication to be

60approved by the Director. (2) The post-injection site care and site closure plan must include the following information: (i) The pressure differential between pre-injection and predicted post-injection pressures in the injection zone; (ii) The predicted position of the carbon dioxide plume and associated pressure front at si te closure as demonstrated in the area of review evaluati on required under § 146.84(b); (iii) A description of pos t-injection monitoring location, methods, and proposed frequency; and (iv) A proposed schedule for submitting post-injection site care monitoring results to the Director. (3) Upon cessation of injection, owne rs or operators of Class VI wells must either submit an amended post-injection site care and site closure plan or demonstrate to the Di rector through monitoring data and modeling results that no amendmen t to the plan is needed. (4) The owner or operator may m odify and resubmit the postinjection site care and site closure plan for the Director’s approval within 30 days of such change. (b) The owner or operator shall mon itor the site following the cessation of injection to show the position of the carbon dioxide plume and pressure front and demonstrate that USDWs are not being endangered. (1) The owner or operator shall c ontinue to conduct monitoring as specified in the Director-approved post-injection site care and site closure plan for at least 50 10 years following the cessation of injection. At the UPON A DETERMINATION BY THE Director ’s THAT THE GEOLOGIC SEQUESTRATION PROJECT MAY POSE AN ENDANGERMENT TO USDWS discretion , THE DIRECTOR, AT HIS DISCRETION, MAY REQUIRE the monitoring will TO continue FOR A TIME PERIOD SPECIFIED BY THE DIRECTOR until the geologic se questration project no longer poses an endangerment to USDWs. (2) If the owner or operator can demonstrate to the satisfaction of the Director before 50 10 years, based on monitoring and other site-specific data, that the geologi c sequestration project no longer poses an endangerment to USDWs, the Director may approve an amendment to the post injection site care and si te closure plan to reduce the frequency of monitoring or may authori ze site closure before the end of the 50 10 year period. (3) Prior to authorization for THE EXPIRATION OF THE 10 YEAR POST-INJECTION SITE CARE PERIOD, site closur e , the owner or operator must submit to the Direct or a demonstration, based on monitoring and other site specific da ta, that the carbon dioxide plume and pressure front have stabilized and that no additional monitoring is needed to assure that the geologi c sequestration project does not pose an endangerment to USDWs.

61(4) IF WITHIN 180 DAYS AFTER THE SU BMITTAL OF THE DA TA REQUIRED UNDER SUBPARAGRAPH (3) ABOVE THE DIRECTOR DETERMINES THAT THE GEOLOGICAL SEQUESTRATION PROJECT MAY CONTINUE TO POSE AN ENDANGERMENT TO USDWS, HE SHALL SO NOTIFY THE OWNER OR OPER ATOR OF HIS DETERMINATION AND THE BASIS THEREFORE, AND If such a demonstr ation cannot be made (i.e., if the carbon dioxide plume and pressure front have not stabilized) after the 50

- year period, the owner or operator must submit to the Director a plan to continue post-injection site care. (5) IF WITHIN 180 DAYS AFTER THE SU BMITTAL OF THE DA TA REQUIRED UNDER SUBPARAGRAPH (3) AB OVE THE DIRECTOR FAILS TO DETERMINE AND TO NOTIFY THE OWNER OR OPERATOR TH AT THE GEOLOGICAL SEQUESTRATION PROJECT MAY CONTINUE TO POSE AN ENDANGERM ENT TO USDWS, SITE CLOSURE SHALL BE DEEMED AUTHORIZED BY RULE (c) Notice of intent for site closure. The owner or operator must notify the Director at least 120 days before site closure. At this time, if a ny changes have been made to the original post-injection site care and site closure plan, the owner or operator must also provide the revise d plan. At the discretion of the Director, a shorter notice period may be allowed. (d) After the Director has authorized site closure OR SITE CLOSURE IS AUTHORIZED BY RULE, the owner or opera tor must plug all monitoring wells in a manner which will not allow movement of injection or formation fluids that endangers a USDW. (e) Once the Director has authorized site closure, OR SITE CLOSURE IS AUTHORIZED BY RULE, the owner or ope rator must submit a site closure report within 90 days that must ther eafter be retained at a location designated by the Director. Th e report must include: (1) Documentation of appropriate injection and monitoring well plugging as specified in § 146.92 and para graph (c) of this section. The owner or operator must provide a copy of a survey plat which has been submitted to the local zoning authority designated by the Director. The plat must indicate the location of the injection well relative to permanently surveyed benchmarks. The owner or operator must also submit a copy of the plat to the Regional Ad ministrator of the appropriate EPA Regional Office; (2) Documentation of appropriate notification and information to such State, local and tribal authori ties as have author ity over drilling activities to enable such State and local authorities to impose appropriate conditions on subseque nt drilling activities that may penetrate the injection and confining zone(s); and (3) Records reflecting the nature , composition and volume of the

62carbon dioxide stream. (f) Each owner or operator of a Clas s VI injection well must record a notation on the deed to the facility property or any other document that is normally examined during title search that will in pe rpetuity provide any potential purchaser of the pr operty the following information: (1) The fact that land has been us ed to sequester carbon dioxide; (2) The name of the State agency, local authority, and/or tribe with which the survey plat was file d, as well as the address of the Regional Environmental Protection Agency Office to which it was submitted; and (3) The volume of fluid injected, the injection zone or zones into which it was injected, and the period over which injection occurred. (g) The owner or operator must retain for three years following site closure, records collected during th e post-injection site care period. The owner or operator must deliver th e records to the Director at the conclusion of the retention period, and the records must thereafter be retained at a location designated by the Director for that purpose.

[45] 40 C.F.R. § 264.117(a)(1)

Individual Response: The post-injection site care require ments in the final GS rule, §146.93(b), incorporate a combination of a 50-year default po st-injection site care ti meframe, in conjunction with a performance standard, for Class VI wells . The GS rule offers owners or operators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe during the post-injecti on 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 demons trate, during the permitting process based on substantial data, that an alternative PISC tim eframe may be appropria te if it ensures nonendangerment of USDWs pursuant to requirements at §146.93(c).

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

EPA believes that a default post-injection site car e timeframe of 50 years, with flexibility to adjust the timeframe for a limited number of GS projects during the permitting process where substantial data exists to demonstrate that an alternative timeframe would be protective of USDWs, or based on data collected during the PISC period, is appropriate to address the range of sites where GS is anticipated to occur, to ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-specific data, and be based on pressure monitoring and USDW impacts. EPA expects that the Director will c onsider the types of information the commenter describes in determining whether the plume a nd pressure front no longer pose a risk of

6364 endangerment to USDWs and post-injection si te care monitoring may be discontinued.

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the guidance will assist Directors in evaluating propo sed well plugging plans a nd post-injection site care and site closure plans under §146.92 a nd §146.93. The guidance describes recommended approaches for how an owner or operator coul d plug injection and monitoring wells, perform post-injection monitorin g, demonstrate the appropr iateness of an alternative post-injection site care time frame, demonstrate non-endangerment, and perform site closure activities. The guidance will be available at h ttp://water.epa.gov/type /groundwater/uic/wells_sequestration.cfm.