This comment letter response contains two parts:   

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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 

Underground Injection Control (UIC) Program for Carbon Dioxide 

(CO2) Geologic Sequestration (GS) Wells; Proposed Rule

Docket ID No. EPA–HQ–OW–2008–0390

(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. Evans
Table 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 “buoyancy”; the scale of current injections and 

storage; and corrosion.................................................................................... 6

1. CO2 is not inherently “buoyant”; rather it is simply denser than some 

underground gases, fluids or liquids, while less dense than others. Such 

relative differentials in density do not create an upward “force” as 

suggested by the NOPR’s definition. ....................................................... 7

2. Contrary to statements in the NOPR, the scale of CO2 injections 

anticipated to be captured from coal-fired power will be far less – not 

greater – than the scale of existing CO2 injection operations for many 

years and therefore does not justify the proposed new regulations at this 

time. ...................................................................................................... 10

3. The Proposed Rule overstates the corrosivity of CO2, which is not at all 

corrosive except in the presence of free water. ....................................... 12

B. The Proposed 50-year Term for Post-Injection Site Care Is Unreasonably 

Long ........................................................................................................ 15

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

CERCLA ........................................................................................................ 17

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

RCRA ........................................................................................................ 18

B. EPA Should Exclude Injection and Geologic Storage of CO2 from Coverage 

Under CERCLA.......................................................................................... 20

IV. Suggested Changes to Language of Proposed Rule ....................................... 22

A. § 146.82 Required Class VI permit information.......................................... 22

B. §146.84 Area of review and corrective action. ............................................. 23

C. § 146.86 Corrosiveness of the carbon dioxide stream, and formation fluids. 23

D. § 146.87 Logging, sampling, and testing prior to injection well operation.... 25

E. § 146.88 Injection well operating requirements............................................ 28
ii

F. § 146.89 Mechanical integrity. .......................................................................... 30

G. § 146.90 Testing and monitoring requirements.................................................. 30

H. § 146.92 Injection well plugging. ...................................................................... 32

I. § 146.93 Post-injection site care and site closure. .............................................. 32
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”).1 Analysts 

worldwide have identified carbon capture and storage “CCS” as one of the essential 

components of any successful strategy for lowering such emissions.2 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 addition to existing 

injection and incidental storage of CO2 in enhanced oil or gas recovery operations 

(“EOR” or “EGR,” respectively)) through Class II wells. In many respects, the Proposed 

Rule appears well-suited to advance that objective and EPA deserves credit for having

developed a comprehensive approach to a complex set of issues. In other respects, 

however, the Proposed Rule appears to misapprehend certain core facts relating to the 

physical properties and behavior of CO2 in some underground formations, the scale of 

existing CO2 storage operations 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 protection of underground sources of 

drinking water (“USDWs”) and a few that would even prove counterproductive. 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 time 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 Class 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.

We are therefore concerned that the Proposed Rule, as presently drafted, will 

increase the cost of geologic storage3of CO2 without producing commensurate benefits 

1

See generally Regulating Greenhouse Gas 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 CO2 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 Union’s “Proposal for a Directive of the 
2

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 risk 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. 

We are also concerned that certain unnecessary and costly requirements in the 

Proposed Rule would discourage, or even foreclose, the conversion of existing Class II 

EOR wells to Class VI geologic sequestration wells. This 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 governments worldwide believe that it must play in any successful strategy 

for reducing atmospheric concentrations of CO2. This is important because it means 

that the EPA may – and indeed, must – balance objectives that pull at times in competing 

directions. In other words, if the EPA’s primary objective is to reduce CO2 emissions 

and if CCS is an essential component of a CO2 reduction strategy, then the rules 

governing CO2 injection and storage must be crafted in such a way as to advance the 

primary objective of reducing GHG emissions. 

New rules for CO2 sequestration that are too risky or too costly for widespread 

use will work against this primary overall objective of reducing GHG emissions. Absent 

a broader legal foundation than the SDWA alone, however, the EPA could conceivably 

find itself required to impose 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 

purpose 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 

foundation for the new sequestration rules.

Detailed comments on the Proposed Rule are provided below in Section IV of 

these comments, together with specific suggested changes to the proposed regulatory text 

that may help EPA accomplish its stated objectives. Before undertaking that section-bysection analysis, however, we first 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 based 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.4 Moreover, 

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://cdm.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 

Supporting documents referenced in the Proposed Rule. See Meyer, “Summary of Carbon Dioxide 

Enhanced Oil Recovery (CO2 EOR) Injection Well Technology,” (EPA Document Identification: 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 injections of 0.044 GMT) (hereafter “Meyer”). While 

the Meyer document is not available from regulations.gov, it is published on the Ground Water Protection 
3

the rules should also provide for the possibility that a former EOR well converted to use 

for Class VI CO2 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 existing EOR sites would complement the more 

extensive rules to govern CO2 injections 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 site 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 sequestration because they have proven traps 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 anticipated 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: Geologic CO2 Sequestration Technology and 

Cost Analysis (June 2008) at 2 (hereafter “EPA Technology and Cost Analysis”).5The 

same point was made 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 likely to be injected into saline formations over 

the long term, it is anticipated that, given the experience and the availability 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 material quantities of CO2 are captured from coal-fired electricity 

generating facilities.6In addition, much of the actual research in examining the 

Council’s website at: http://www.gwpc.org/e-library/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/fdmspublic/ContentViewer?objectId=09000064806418c4&disposition=attach

ment&contentType=pdf (last visited November 10, 2008). 

6 Transactions to purchase CO2 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 CO2” (November 8, 2006); Press Release, Denbury 

Resources, Inc. “Denbury Signs Agreement to Purchase Additional Manufactured CO2” (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) to 
4

movement of CO2 plumes in saline formations is still in the early stages, with full results 

not expected for several years,7and EPA’s rules may well need to be modified once the 

results of those extensive research projects are obtained.

Under the existing UIC rules for Class II wells, however, CO2 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).8The 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 operations 

to the incremental storage of CO2 captured from industrial or power plant sources once 

the oil production operations have ended. It is true that these sites would not be adequate 

to accommodate all of the CO2 that would be captured if such capture technology were 

deployed on all new power plants. But 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 years.9 Hence what is relevant here is that 

existing EOR-focused sites will be generally adequate and available to accommodate 

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 missing an opportunity to craft a practical 

transitional pathway that builds on the large scale CO2 injection and storage operations 

that are incidental to existing EOR operations to incremental storage of CO2 that could 

begin following termination of a given EOR operation. EPA should consider such a 

transitional pathway from incidental to incremental storage at existing well-defined sites 

produce hydrogen-rich synthesis gas for power generation while capturing approximately 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 research projects on geologic storage of CO2 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 recovery 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 22nd projected plant in the year 2030, total CO2 injections would appear 

to be significantly less than – perhaps only half – the current CO2 injections 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 Sequestration 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 373.1 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 CO2 cumulatively over the next 25 

years). This suggests average CO2 injections from power plants of approximately 14.92 million metric 

tonnes per year over the next 25 years, or roughly 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 Support Document: Geologic CO2

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 projection for 

CO2 sequestration for twenty-five year period 2012-2036).
5

with existing CO2 handling facilities as a supplemental or complementary approach to the 

Proposed Rules. 

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 addressed in the near term to allow for incremental storage of CO2 in 

formations where very large quantities 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 adopted in place of the current Proposed 

Rule that offers a limited transition mechanism for Class II wells or as an optional 

alternative. It should of course include verification, 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 

results of ongoing research and the pace of deployment of capture technology for 

electricity power plants become better known. 

Accordingly, Denbury urges EPA to better recognize the fruits of existing 

experience with injection and storage of large volumes of CO2 that are necessarily 

incidental to EOR operations. That existing experience is particularly important because 

it suggests strongly that the initial CO2 injections for geologic storage 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 industry experience will necessarily apply to 

the movement of CO2 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 CO2 plumes in such formations. Nonetheless, where the CO2 has already 

been injected in previously defined reservoirs using approved well construction 

techniques and permitted by the proper state authorities, it should be possible to continue 

CO2 injections for geologic storage purposes subject to appropriate additional 

monitoring, reporting and well closure-related requirements. 
6

II. THE PROPOSED RULE WOULD IMPOSE UNDUE AND UNNECESSARY COSTS

BASED ON AN ERRONEOUS UNDERSTANDING OF ACTUAL FIELD

EXPERIENCE IN INJECTING CO2 IN CLASS 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 administrative agencies where “a 

month of experience will be worth a year of hearings.”10 In the case of CO2 injection and 

incidental storage during 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. 

According to the documents in the current record, state permitting authorities have issued 

permits for approximately 13,000 Class II wells to inject CO2 for EOR operations, over 

6,000 of which are actively injecting each year in excess of 44 million metric tonnes of 

CO2.

11 While that experience is focused on injections into well-defined oil and gas 

bearing formations, rather than saline formations, many of the operational lessons learned 

relate directly to appropriate well construction requirements for CO2 injection wells, 

corrosion management for injection and production wells, as well as pipelines and 

associated CO2 handling facilities. We respectfully urge EPA to give greater weight to 

that extensive real-world experience than currently given under the Proposed Rule.

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

volumes, pressures, and certain physical characteristics of the CO2 injectate for geologic 

storage are “unique.”12 The basis for the belief that CO2 injectate for geologic storage is 

“unique” is apparently based 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 Levanthal, J.). Judge Levanthal’s 

opinion 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) and 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 Meyer, 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/elibrary/e-library_documents/e-library_documents_co2/Argonne%20Report%20CO2%20Resources.pdf

(last visited November 10, 2008) at 8 (Table 3) (listing CO2 injection wells by state and by UIC well 

class)). The number of active CO2 injection wells is also 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 CO2 injections for geologic storage. 

See e.g., NOPR, supra, 73 Fed. Reg. at 43,492, 43,495, 43,502, 43,504, etc. 
7

(a) the “buoyant” nature of CO2;

13

(b) the large scale of CO2 injections anticipated to be captured from coal-fired 

power plants as compared to CO2 injections for EOR purposes;14 and

(c) the corrosivity of CO2 in the presence of free water.15

The Proposed Rule thus states that the regulatory alternative selected was chosen 

“because of the volumes of CO2 being anticipated for long-term storage, the buoyant and 

viscous nature of the injectate, 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”; rather it is simply denser than some underground 

gases, fluids or liquids, while less dense than others. Such relative differentials in density 

do not create an upward “force” as suggested by the NOPR’s definition.

The preamble to the Proposed Rule makes very clear that the changes to the UIC 

program for CO2 sequestration are based on the assertion that CO2 is “buoyant.”16 This is 

simply incorrect. CO2 is a non-explosive, non-flammable, non-toxic gas that possesses 

different physical properties than some other 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 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 (defining buoyancy as “[u]pward force on one phase (e.g., a fluid) 

produced by the surrounding fluid (e.g., a liquid 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 CO2 rises in the formation 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 properties 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 mixed with water); at 43,505 (stating that 

“buoyancy of CO2 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 CO2”); id. (stating that computational models used to delineate the area of review consider inter alia

the “buoyant nature” of the injected CO2); at 43,509 (basing proposed enhancement to deep well 

construction procedures “[d]ue to the buoyancy of CO2” in order to provide additional barriers to CO2

leakage outside of the injection zone); at 43,512 (“buoyancy of CO2” 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 CO2 storage to address the “unique properties of CO2, specifically its buoyancy and potential 

corrosivity”); id. (same, referencing need for tailored testing requirements “because of the buoyant and 

corrosive properties” of the CO2 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 43,519 (stating that area over which CO2 will spread is likely to be larger than for existing 

well classes “[g]iven the buoyancy of CO2, viscosity, and large injection volumes” associated with geologic 

storage of CO2); and at 43,528 (stating that current regulatory requirements do not specifically consider 

“injection of a buoyant corrosive fluid”). 
8

include any special buoyancy characteristics or properties. Rather, CO2 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 relative densities of the various fluids or gases that 

are in the reservoir. The various materials will simply segregate based on the relative 

densities of the fluids 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 fluids within the system. 

For example, if CO2 is injected in a system 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 contains natural gas (i.e., methane), the CO2 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 become “buoyant” as defined by the Proposed Rule or exerts any 

incremental “upward force.” Nor does it mean that CO2 acquires some special downward 

force. It simply means that natural gas is relatively less dense than the CO2 and hence the 

two substances will tend to separate with the natural gas above the CO2. To reiterate: the 

relative depths, pressures and fluids within 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 supporting documents for the Proposed Rule. 

For example, the Vulnerability Evaluation Framework17 explains that:

Supercritical CO2 is less dense and more buoyant than oil and 30% to 50% more 

buoyant than saltwater. As a result, 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 reservoirs. As 

temperature increases, the density of supercritical CO2 decreases at a given 

pressure, but increases with increasing pressure at a given temperature. Similarly, 

the viscosity of supercritical CO2 decreases with increasing temperature at a given 

pressure, but increases with increasing pressure at a given temperature. As 

temperature and pressure increase with subsurface depth, the density and viscosity 

of supercritical CO2 injected will be determined by the specific pressure and 

temperature conditions. Finally, when CO2 dissolves, it shares the physical 

properties of the substrate (e.g., saltwater) and no longer behaves independently.

The Proposed Rule does not incorporate this 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:

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 partially immersed, caused by differences in 

pressure or density.

73 Fed. Reg. at 43,493 (emphasis added). This use of the word “force” is scientifically 

inaccurate and generates connotations that there are additional forces created when CO2

is injected into the subsurface for sequestration. This is not the case, however, as there 

are no additional or different forces associated with CO2 injections than there are with the 

injection of any other fluid or gas. The injection of any fluid into the subsurface creates a 

transient pressure wave that is greater at the injection site and diminishes significantly at 

positions located away from the injection 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 focus 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 bottom 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 endow 

the CO2 with any buoyant force, however. The issue is not “buoyancy,” but merely 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 injectate” is cited as a key reason why “...EPA is 

proposing changes to the existing UIC approach or requirements in several program 

areas...” 73 Fed. Reg. 43,504. This misunderstanding of how injected CO2 behaves 

underground is repeated at multiple points in Sections 1, 2, 3, 4, 5 and 8.18 The fact that 

the significant new regulatory regime set forth in the Proposed Rule is based to such a 

great extent on factually and technically erroneous information 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 should lead EPA to find the existing UIC

methodologies and rules generally sufficient to address CO2 injections for geologic 

storage in oil and gas bearing formations. In other words, Class II regulations and 

requirements should be used with the addition of requirements for long term monitoring

if, for example, 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 requirements have 

proven successful in protecting underground sources of drinking water for almost 40 

years and thus modifications or additions are more appropriate than establishing a 

completely new well classification.

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.
10

2. Contrary to statements in the NOPR, the scale of CO2 injections anticipated to be 

captured from coal-fired power will be far less – not greater – than the scale of existing 

CO2 injection operations for many years and therefore does not justify the proposed new

regulations at this time.

The second basis for the Proposed Rule’s conclusion that CO2 injections for 

geologic storage are “unique” is the statement that the scale of these injections will be on 

a scale that is much larger than other types of UIC injection operations.19 This is simply 

erroneous. For example, the EPA Cost Analysis assumes cumulative injections of 350 

million metric tons of CO2 over the next 25 years.20 Yet as the NOPR itself recognizes, 

this is only about half the quantity of CO2 that has already 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 annual injections at approximately 44 million metric tones per year.21

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 – the 

equivalent of approximately 13.4 million metric tonnes -- the great majority of which was 

injected for EOR operations.22 In other words, the scale of operations of this one 

company – which is not the largest participant in the EOR industry – is essentially the 

same by itself as EPA’s projected average injection rate for geologic storage for the entire 

nation of 14 million tonnes per year over the next 25 years (as published in the NOPR’s 

Cost Analysis (350 million metric tonnes cumulative injections over 25 years divided by

25 years = 14 million tonnes per year)).23

19 See, e.g., 73 Fed. Reg. 43,506 (stating 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); 73 Fed. Reg. at 43,518 (requirement to address 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 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 recovery operations, “which currently inject CO2 on a relatively small scale”).

20 73 Fed. Reg. at 43,527. This estimate is within the range of other published estimates. For example, the 

IPCC 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 separately 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 Carbon 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 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/elibrary/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_August2007.pdf (last visited 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 

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 

power plants) is expected to remain the case for decades. It is only in some distant future 

that injections of powerplant CO2 are anticipated to approach 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,

24 this statement is not 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 captured from a 500 MW 

power plant, or roughly 2.4 million metric tonnes per year25– an average of just 6,575 

metric tonnes per day. This amounts to less than 5 percent -- one-twentieth -- the level of 

current Class II CO2 injections (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 

pressure front of a full-scale GS project will be “much larger” than for CO2 injections for 

EOR purposes; the facts are quite the reverse: The scale of current CO2 injections through 

existing Class II wells is already vastly larger than the scale 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 are not appropriate for long 

term sequestration, especially when dealing with deep saline formations 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 CO2 into saline formations, as a 

framework for allowing the transition of the existing and planned universe of CO2 wells 

from EOR operations to long term geologic sequestration operations. Further 

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 that point, such rules would 

properly be based on additional years of research regarding the movement of a CO2

24 73 Fed. Reg. at 43,506. 

25 The estimate of 3 million metric tonnes 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 

Future 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.
12

plume in a saline formation, the experience of the state Directors with monitoring and 

remediation activities, etc. 

3. The Proposed Rule overstates the corrosivity of CO2, which is not at all corrosive 

except in the presence of free water.

The third basis for the Proposed Rule is the potential corrosivity of CO2.

26 The 

Proposed Rule specifically seeks comment regarding requirements for degradationresistant well construction materials, such as acid-resistant cements and corrosionresistant casing. The NOPR correctly states that CO2 mixed with water will form 

carbonic acid (H2CO3) and that carbonic acid is corrosive of cement -- a fact that has long 

been taken into account in existing permitting procedures and industry practices. 

However, the preamble to the Proposed Rule appears to overstate the corrosivity of CO2

under actual geologic storage conditions. For example, the NOPR references (73 Fed. at 

43,510) the actual field experience and observations from wells that had been exposed to 

a CO2-water environment for 30 years, but then appears to largely dismiss the results on 

the grounds that this actual field corrosion experience is “surprisingly” low (presumably 

in light of a referenced laboratory study that found much more rapid corrosion than has 

in fact been experienced).27 In contrast, a study that reviewed actual samples exposed to 

a CO2-water environment for 30 years was seemingly dismissed as involving “only 

limited examples,” while the contradictory laboratory study was apparently given greater 

weight.28

The Proposed Rule appears to downplay other research publications that conclude 

that conventional Portland-based well cements have been adequate to guard against 

corrosion from CO2 mixed with water. For example, the Proposed Rule cites Meyer 

(2007)29, but doesn’t recognize that Meyer notes that non-Portland cements have not been 

widely used in CO2 EOR applications, and have been applied instead to resist “very 

severe acid gas (CO2 and H2S) and highly corrosive geothermal brine exposure 

conditions.” Meyer (2007), supra, n. 4 at 18. Dr. Meyer also noted the actual experience 

from a 52 year old well with conventional, Portland-based well cement, that had been 

exposed to CO2 for 30 years in EOR operations and no significant wellbore failure had 

26 See 73 Fed. Reg. at 43,503 (design changes are being proposed to address mobility “and corrosivity” 

caused by long term GS of CO2); id., at 43,504 (EPA proposing changes “[b]ecause of” the volumes of CO2

being anticipated for long-term storage, the buoyant and viscous nature of the injectate, “and its corrosivity 

when mixed with water”); id. at 43,509 (pointing to the “potentially corrosive nature of the injectate” in the 

design and construction of CO2 GS wells and noting that “CO2 mixed with water or impurities (NOX, SOX

and H2S) can be corrosive to well materials and cements” and expressing concern that “conventional” 

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

27 73 Fed. Reg., at 43,510 

28 Id. (“[a]though the field corrosion looks surprisingly low, these are only limited examples. Laboratory 

studies are conducted under aggressive chemical conditions in an attempt to mimic the cumulative effects 

of long-term exposure to CO2-rich formation fluids. Given the high injection rates, long lifespan, and 

potential impurities in GS, careful selection of acid-resistant materials and practices may be necessary). 

29 Meyer, supra, n.4. 
13

been observed. Id. (referencing Carey, et al. 2007).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 show evidence of exposure to CO2, the structural integrity of the 

recovered cement core, petrographic observations, air permeameter data, and cement 

bond log indicated that “the cement retained its capacity to prevent significant transport 

of fluid through the cement matrix.” Id. at 84; see also at 78 (“no obvious evidence for 

CO2 interaction” in the shale caprock); id. (core bond log showed “no evidence of CO2-

induced de-bonding or channel formation at or near the reservoir contact”); id. (“most 

basic observation of the SACROC core” is that the Portland cement at the studied well 

“survived and retained its structural integrity after 30 years in a CO2-reservoir

environment”). 

Finally, the record here should be supplemented with additional laboratory 

research published after the Proposed Rule, the results of which suggest a rate of 

degradation of Portland cement under conditions mimicking geological sequestration that 

is far less than the study cited in the Proposed Rule. See Kutchko, et al. “Rate of CO2

Attack on Class H Well Cement under Geologic Sequestration Conditions” (hereafter 

Kutchko, 2008).31 While the details of the research merit careful consideration, and 

additional research is currently underway, the conclusion of this August 2008 research 

publication is worth quoting: 

Based on the alteration process, penetration depths, and rates of alteration 

observed in this study, and on penetration depths observed in field samples 

exposed to CO2 for ~30 years, it is unlikely that alteration of these cements via 

cement matrix diffusion of supercritical CO2 or CO2-saturated brine would lead to 

significant alteration in well completions that are properly cemented with Class H 

neat cement after decades of exposure to supercritical CO2 or CO2-rich brine. 

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

This research is reinforced by other papers presented at a major international 

conference on greenhouse gas control technologies, the 9th International Conference on 

Greenhouse Gas Control Technologies (hereafter cited as “GHGT-9”) that we commend 

to the agency’s attention, including in particular: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 

Performance of Oil Well Cement with 30 Years of CO2 Exposure from the SACROC Unit, West Texas, 

USA,” preprint submitted to International Journal of Greenhouse Gas Control, October 18, 2006. The 

citation to the published report is 1 International Journal of Greenhouse Gas Control, pages 75-85 (2007). 

31 Barbara G. Kutchko, Brian R. Strazisar, Gregory V. Lowry, David A. Dzombak, and Niels Thaulow, 

“Rate of CO2 Attack on Class H Well Cement under Geologic Sequestration Conditions,” Environmental 

Science and Technology, vol. 42, number 16 (August 15, 2008), at 6237-42. 

32 “GHGT-9, 9th International Conference on Greenhouse Gas Control Technologies,” (November 16-20, 

2008) Washington DC (http://mit.edu/ghgt9/) (hereafter “GHGT-9 Conference” (organized by MIT in 

collaboration with the IEA Greenhouse Gas R&D Programme (IEA GHG), with major sponsorship from 

the U.S. Department of Energy). All papers presented at the GHGT-9 Conference are available from the 
14

· Duguid, “An estimate of the time to degrade the cement sheath in a well exposed 

to carbonated brine,” summarizing (at 3-4) recent physical research on cement 

carbonation and describing own research. In sum, Duguid’s recent experiments 

indicate (at 8) that for a well that has good zonal isolation and no pathways for 

flow, “the rate of degradation will be between 30,000 and 700,000 years to 

degrade 25 mm of neat paste in a sandstone reservoir, and possibly longer to 

destroy the cement passing through the cap rock.”33

· Crow, Williams, Carey, Celia, and Gasda, “Wellbore integrity analysis of a 

natural CO2 producer,” at 8 (concluding, inter alia from analysis of 30 year old 

well from a natural CO2 production reservoir that Portland-based cement systems 

“can be used effectively in creating suitable barrier systems for long-term CO2

storage operations, if good practices are employed during well construction”); 

· Benge, “Improving wellbore seal integrity in CO2 injection wells” (reviewing 

recent research and noting (at 2) that applying the formula developed by BarletGouedard, et al., it would take “several hundred centuries” – tens of thousands of 

years -- to degrade 6 meters of wellbore cement (even assuming a continuous and 

renewable supply of fresh CO2 with no other inhibiting reactions occurring).

· Aiken, “An Introduction to the IEA GHG International Research Network on 

Wellbore Integrity.” The paper reviews the work of the IEA’s International 

Research Network on Wellbore Integrity founded some 4 years ago and noting (at 

1, 6) the importance of analyzing the differences found between laboratory 

experiments and corresponding field findings, and if necessary, designing new 

laboratory experiments to better replicate field conditions.

A great deal of other original research was presented as well, underlining the dynamic 

nature of research in this area and reinforcing the importance of avoiding overlyprescriptive requirements that are unnecessary based on experience in the field. 

We concur with the Proposed Rule’s general principle that cement and cement 

additives must be “compatible with the carbon dioxide stream and formation fluids” and 

“of sufficient quality and quantity to maintain integrity over the design life” (Section 

146.86 (b) (5)). However, we are concerned that the rule contains prescriptive well 

construction and monitoring requirements that do not appear necessary in light of actual 

field experience and the more recent laboratory research referenced above. At a 

minimum, the more recent research suggests that EPA should defer imposing these 

conference website at: http://mit.edu/ghgt9/papers/index.html (last visited December 12, 2008) and through 

the site’s search portal at: https://www4.eventsinteractive.com/iea/rs.esp?id=270005&scriptid=sppp1 (last 

visited December 12, 2008). 

33 It should be noted that these results are quite different than in a 2006 paper by some of the same 

researchers which EPA included among the supporting materials in this proceeding. Compare A. Duguid, 

M. Radonjic, R. Bruant, T. Mandecki, G. Scherer, and M. Celia “The Effect Of CO2 Sequestration On Oil 

Well Cements” (Document ID: EPA-HQ-OW-2008-0390-0013) (posted by EPA July 25, 2008). 
15

additional costly requirements pending the fruits of the further field experience and 

research. 

We would also call to EPA’s attention other recent research from the GHGT-9 

Conference that is relevant to this rulemaking with regard to the carbon content of oil that 

could be produced via CO2 injection of captured CO2 emissions. Ferguson, et al. 

reviewed the net carbon content of oil produced via CO2-based EOR, taking into account 

the storage of residual CO2 that remains stored as a normal incident of EOR production 

operations. The researchers calculated that oil produced through injection of captured 

CO2 emissions would be roughly 70 percent “carbon free” under current technology. See

Ferguson, Nichols, Leeuwen, and Kuuskraa, “Storing CO2 with Enhanced Oil Recovery” 

(“Ferguson, et al. 2008”) 34 The authors estimate that next generation CO2 storage 

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 and 2030. This capability of the U.S. oil industry to 

reduce the net carbon content of new oil supplies is an aspect of the sequestration debate 

that is not addressed in the Proposed Rule, but illustrates how targeted technological 

innovation can reduce carbon emissions 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 

monitoring during post-injection site care. Our objection stems from the relative risks 

associated with the various phases 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 

financial assurance and the sagacity of other regulatory proposals. 

First, we believe that published and reputable literature suggests that a 50-year 

timeframe for post-injection site care is too long and wholly unrelated to the risks 

associated with geologic storage. For well-sited, characterized, operated and managed 

sites, the risks accumulate during the operational phase, but decline as sites move from 

post-injection site care to closure to eventual long-term care. Prevailing scientific 

opinion expects the risk profile to diminish with time.35 As Lindene and Trabucchi 

suggest, “the risk of some 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 and 

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

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

dioxide more than 10 years after termination of injection will become increasingly remote 

due to geochemistry conditions.”

36 The geochemistry conditions they reference include 

the four main mechanisms which trap CO2 in well-chosen geological formations – 1) 

structural trapping -- which is addressed in the proposed rule and is not necessary to 

discuss further here; 2) residual CO2 trapping -- where CO2 is trapped by capillary forces 

in the interstices of the rock formation, a process which develops about 10 years after 

injection; 3) dissolution or solubility trapping -- where the CO2 dissolves into the brine 

found in the geological formation and sinks because the 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) mineralization or mineral trapping -- which occurs when 

dissolved CO2 chemically reacts with the formation rock to produce minerals, a process 

requiring hundreds of years.37

Given that the greatest risk of a release occurs during the operational 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-injection site care timeframe simply does not correlate to the 

relative risks associated with geological storage and the function of geologic trapping 

mechanisms that limit the risk of unexpected releases of CO2 after the termination of 

injection activity.

Furthermore, other respected models use a much shorter period. For instance, the 

IOGCC Model Rules and Legislation stipulate a 10 year post-injection site care period.38

Under the IOGCC Model, the operator of the storage 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 plainly 

related to the relative risks of geologic storage and the geochemical reactions discussed 

above. Also, in the preamble, EPA acknowledges that a 30-year post-closure care period 

is recognized as the industry standard for the injection of hazardous waste.39

Finally, this 50-year timeframe raises barriers to obtaining financial assurance for 

prospective projects. Section 146.85 of the Proposed Rule requires the owner or operator 

to maintain financial responsibility for corrective action, injection well plugging, postinjection site care and site closure. Undoubtedly owners/operators will enter the private 

sector financial assurance market for some period in order to meet this requirement. An 

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, supra n.2, at 208; see also Benson 2007, supra n.35. 

38 See generally IOGCC, “Storage of Carbon Dioxide in Geologic 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 responsibility is at Model General Rules and 

Regulations, 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 accordance 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-injection site care timeframe creates impediments to 

managing this financial responsibility. We believe that both an indeterminate or an 

exceedingly long post-injection site-care period will discourage the development of 

private sector products to address financial responsibility and discourage sequestration in 

general.

Given the limited risk profile of the 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 science, unnecessary to protect 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 supported by the relative risks involved and 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.

III. ANY FINAL RULE MUST CLEARLY ADDRESS POTENTIAL EXPOSURE UNDER RCRA

AND CERCLA

EPA can and should simultaneously 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 its obligations to protect the nation’s USDWs from both naturally-occurring and 

man-made contaminants, while at the same time promoting progress towards successful 

commercial-scale carbon capture and storage in order to address broader environmental 

protection concerns. 

If EPA is going to address these broader concerns by establishing a framework for 

the injection and sequestration 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 CERCLA40 and RCRA41. Liability under 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 liability. When Congress passed CERCLA, it imposed joint and several 

liability on landowners, transporters, and generators of hazardous substances and it made 

that liability retroactive. Most recently, the Supreme Court, in Massachusetts v. EPA,

549 U.S. 497 (2007), recognized that the Clean Air Act (“CAA”), with its “capacious” 

definition of air pollutant, could be used to regulate substances (in this case, CO2) which 

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

9601-9675. 

41 Resource Conservation and Recovery Act (“RCRA”), 42 U.S.C. § 6901-6992k. 
18

Congress appeared to not intend to regulate and whose regulation under many provisions 

of the CAA (i.e., the NAAQS) is awkward at best. One lesson from these statutes and the 

Courts’ interpretation is that regulated industry cannot underestimate its potential liability 

for pollution, irrespective of its compliance with current regulations and irrespective of

the magnitude of its role in the waste disposal 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 regulatory clarity as to compliance obligations and potential 

for liability. 

A. EPA Should Ensure Clarity Regarding 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 that 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 whether 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 resolve this issue 

could inhibit permitting of wells under the proposed new Class VI regime. 

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

mobility and corrosivity caused by long term geologic sequestration of CO2, and not the 

long term storage of hazardous wastes. EPA seeks comment on its definition of “carbon 

dioxide stream” to exclude hazardous wastes: 

“Carbon dioxide stream means carbon dioxide that has been 

captured from an emission source (e.g., a power plant), plus 

incidental associated substances derived from the source materials 

and the capture process, and any substances added to the stream to 

enable or improve the injection process. This subpart does 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 previously excluded certain substances 

from coverage under 40 C.F.R. § 261.2. CO2 is not excluded under this section, but it is 

also not specifically included as a hazardous 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 stringent handling, storage, and disposal procedures above what would be 

required by the Proposed Rule (except with regard to the post-closure period for financial 

responsibility, which, at 30 years, would be less demanding than the proposed 50 year 
19

term for a Class 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 comment in the proposed rule. RCRA defines solid 

waste to include “discarded material, including solid, liquid, semi-solid, or contained 

gaseous material resulting from industrial . . . 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 use in EOR or EGR activities 

should be explicitly excluded as it would 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 subject 

to these provisions. 

Using authority granted by RCRA § 3001, EPA has exempted from RCRA’s 

definition of solid waste certain low-toxicity wastes that exist in high-volumes, including 

domestic sewage, mining wastes, and certain 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 solid waste even where it cannot be sold 

and used for EOR operations. 

Even if EPA decides not to exclude or exempt 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, concentration, 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 the spectre that the 

injection of CO2 in conjunction with hazardous components could 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 associated with the exploration, development, and production of 

crude oil, natural gas, and geothermal energy. See Regulatory Determination 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 

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, perhaps by anti-CCS activists, and the maintenance of which would 

irreversibly chill CCS projects.
20

B. EPA Should Exclude Injection and Geologic 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 contain hazardous substances or that the CO2

stream could react with groundwater to produce hazardous substances, and concludes that 

“whether or not there is a ‘hazardous substance’ that may result in CERCLA liability 

from a sequestration facility depends entirely on the make-up 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 “federally 

permitted releases,” including releases in compliance 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 

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 for CERCLA liability will deter efforts to 

develop CCS projects. Under CERCLA, private parties or government entities can sue to 

recover “response costs” associated with any “release” from a “facility” of a “hazardous 

substance.” Liability is retroactive, joint and several, and falls upon both current and past 

owners of facilities, and on those who generated or transported those “hazardous 

substances.” 42 U.S.C. § 9607(a). The broad nature of CERCLA liability makes it a 

vigorous 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 CO2 is non-toxic at low concentrations 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 envisioned when it enacted CERCLA, the definition that 

Congress included in the statute is reminiscent of the “capacious” definition of “air 

pollutant” that the Supreme 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 showed 

no intent to do when it enacted the Clean Air Act. To avoid a similar outcome here, the 

EPA should define that the injection of CO2 under a Class VI permit constitutes a 

“federally permitted release.” 

EPA’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 

United 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 
21

permitted release exemption (the “FPR exemption”). In 1988, it stated in the preamble to 

a proposed rule that would have clarified the FPR exemption that “any underground 

injection of hazardous substances permitted under a State program . . . or EPAadministered program, is considered federally permitted for purposes of CERCLA 

notification.” Reporting 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 CERCLA 

cleanup liability under section 9607. 

To be sure, this would be a narrow exemption, 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 position 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 were not expressly permitted in the various permits, which exceeded the 

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 

recognize the applicability of the FPR exemption without significantly revising its 

position on the FPR. 

Yet another basis on which to exclude injected 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 purchase anthropogenic CO2 from multiple sources. While the 

price of the CO2 varies, it has a significant value to Denbury and other EOR operators. 

As discussed above, the most realistic path for storage of CO2 over the next several years 

is incidentally in oil and gas bearing formations. Thus, captured anthropogenic CO2 will 

be a commodity for purposes of EOR for many years.42 Further, 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 CERCLA’s coverage. 

To be sure, EPA does not have the authority to protect CCS operations from 

liability under state statutes and common 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 engaging 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 purposes around 7,500 million metric tonnes between now and 2030). 
22

IV. SUGGESTED CHANGES TO LANGUAGE OF PROPOSED RULE

A. § 146.82 Required Class VI permit information

This section of the proposed rule sets forth the information which the owner or operator 

must submit to the Director in order 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 

prior to well drilling (applicants will not drill the well until it has been approved, 

otherwise they risk drilling an unusable well). Still other data can only be obtained after 

injection activities have been initiated. Post-drilling and post-injection data should not be 

required as part of the application process but instead should be considered confirmatory 

data that may be submitted after 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 initial permit application, and only those data that may be reasonably obtained 

prior to commencement of installation and operation of the injection well.

1. EPA Proposed: §146.82 (f) Maps and stratigraphic cross sections indicating the 

general 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, where known;

So long as the Applicant proposes to inject CO2 below the lowermost USDW, as 

proposed under the rule, there is no justification to require maps and stratigraphic cross 

sections for the entire extent of those USDWs above the lowermost USDW, although 

mapping and stratigraphic cross sections in the immediate vicinity of the proposed 

injection 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 subparagraph (f) should be modified as follows:

(f) Maps and stratigraphic 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;

2. EPA Proposed : §146.82(l) The results 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 subparts (l), (r) and (s) of § 146.82 cannot be met until after the well 

is drilled. For example, subparagraph (l) references (j), formation testing. Clearly 

formation testing is a drilling or post completion operation. Similarly, logging and 

mechanical integrity testing also are drilling or post well completion operations. Because 
23

this information will be collected post 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. 

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 project. 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 project. 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 that the proposed rule 

be amended as follows:

§146.84 Area of review and corrective action.

(a) The area of review is the region surrounding the geologic sequestration project 

that may be impacted by the injection activity. The area of review is based on 

computational modeling that, to the extent practicable and to the extent 

determined to be necessary by the Director, accounts for the material physical 

and chemical properties of 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, the Director is required to determine and specify casing and 

cementing requirements to ensure that a proposed Class VI well is constructed and 

completed to prevent the movement of fluids into or between USDWs or into any 

unauthorized zones and to permit appropriate testing and monitoring. The proposed rule 

does not adequately explain or justify the information requirements set forth therein.

1. EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells.(1)(v) 

Corrosiveness of the carbon dioxide stream, and formation fluids;

The proposed rule requires an applicant to submit to the Director information on the 

corrosiveness of the carbon dioxide stream, and formation fluids. Neither the proposed 

rule nor the Preamble adequately explains whether the information requested is 

corrosiveness of the combined streams of CO2 and formation fluids, or each independent 

stream (which seems unnecessary). Further, the proposed rule or the Preamble should 

elaborate on what type of data may be acceptable –laboratory data for hypothetical

streams, empirical testing, analogous wells? Clarification is requested on the 

aforementioned requirements.
24

2. EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells. (3) At least 

one long string casing, using a sufficient number of centralizers, must extend to the 

injection zone and must be cemented by circulating cement to the surface in one or 

more stages.

*

*

*

(5) Cement and cement additives must be compatible with the carbon dioxide 

stream and formation fluids and of sufficient quality and quantity to maintain 

integrity over the design life of the geologic sequestration project. The integrity 

and location of the cement shall be verified using technology capable of 

evaluating cement quality radially and identifying the location of channels to 

ensure that USDWs are not endangered.

Additional proposed requirements affecting casing and cementing of Class VI wells are 

set forth in §§ 146.86 (b)(3) and (5) as quoted above. The requirement to cement the 

casing to the surface is unnecessary, expensive and contrary to best practices. Under 

acceptable best practices, the long string casing would not be cemented to the surface so 

that the pressure between the surface casing and long string can be monitored to 

determine if there is migration between the long-string casing and the surface casing. 

The cementing requirement proposed above would limit the ability to monitor for 

migration of injected fluids, in this case CO2, behind the casing. Additionally, Denbury’s 

field data indicates that the proposed casing and cementing requirements are costly while 

providing limited, if any benefit. According to our findings, under existing Class II UIC 

rules, a conventional cementing program costs approximately $20,000 per well. Under 

the cementing program proposed for Class VI wells the cost could escalate to 

approximately $193,000 per well—a potential $173,000 increase, representing a 10% 

increase in total per well costs.43

Denbury suggests an alternative that protects USDWs, but at a reasonable cost. Rather 

than require cementing of the long string casing to the surface, the proposed rule should 

require cement and cement additives to be compatible with the carbon dioxide stream and 

formation fluids that cover the injection zone and the confining zone, and then require 

standard (API, ASTM International, or comparable standards) industry cements to a 

certain distance above the confining zone. This would place cements that may require 

special additives at the point where USDWs are most effectively protected from the 

mixture of carbon dioxide and formation fluids that could produce carbonic acid.

Denbury suggests the following revision:

§146.86 (b) Casing and Cementing of Class VI Wells. (3) At least one long string 

casing, using a sufficient number of centralizers, must extend to the injection zone 

and must be cemented by circulating cement to the surface injection zone and 

confining zone and an authorized distance above the confining zone,

43 For a typical well completed under Class II UIC rules, the total costs equals $1,700,000.
25

submitted by the permittee and approved by the Director in one or more 

stages.

*

*

*

(5) To protect USDWs, Ccement and cement additives must be compatible with 

the carbon dioxide stream and formation fluids and of sufficient quality and 

quantity to maintain integrity over the design operating life of the well geologic 

sequestration project must be used across the injection zone and confining 

zone. The integrity and location of the cement shall be verified using technology

capable of evaluating cement quality radially and identifying the location of 

channels to ensure that USDWs are not endangered.

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

EPA’s proposed § 146.87 delineates the information a permittee must collect during the 

drilling and construction of a Class VI well, prior to actual injection activities. Although 

the proposed rule generally allows the Director to approve alternative methods that 

provide equivalent or better information, it is not clear that the Director can utilize that 

regulatory flexibility to waive unnecessary, duplicative testing which the proposed rule 

requires in several subparagraphs. 

1. EPA Proposed § 146.87 (a)(2) Before and upon installation of the surface 

casing:...

(ii) A cement bond and variable density log, and a temperature log after the 

casing is set and cemented.

The requirements in §146.87(a)(2)(ii) to secure and submit specified logs before, upon 

and after surface casing installation is excessive. The proposed rule fails to provide a 

sufficient justification for requiring a cement bond and variable density log before and 

upon installation of the long string casing, and requiring a temperature log after the 

casing is set and cemented. Temperature logs are seldom used in the drilling industry to 

determine cement characteristics as they do not provide useful data regarding the bonding 

of cement. The rules should be modified to allow the permittee to select between the 

specified logs and any other logging tool approved by the Director as follows: 

§146.87(a)(2)(ii) A cement bond and variable density log or other approved 

tool, and or a temperature log after the casing is set and cemented. [see § 

146.12(d)(2)(i)(B) Criteria and Standards applicable to Class I nonhazardous 

wells: Construction Requirements.]

*

*

*

(5) Any alternative methods that provide equivalent or better information and that 

are required of and/or approved of by the Director. The Director may waive any 

log or test specified in this subparagraph. 
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 the given geology before the 

casing is installed; and

Once again, the proposed rule requires testing that would be of little benefit in protecting 

USDWs, but would impose significant costs on operators. For example, Denbury sees no 

basis to run a fracture finder log in every well. Fracture finder logs will only see minor 

fractures within the individual formations. The log does not provide information on 

whether these minor fractures can act as conduits between the injection zone and 

confining zone. To avoid unnecessary data collection and submittal, the rules should 

allow the applicant to propose and justify a logging suite based on the reservoir and 

geology associated with the particular CO2 project. The Director of course should be 

allowed to approve, or recommend revisions to the proposed suite. This would avoid 

mandating unneeded testing. Denbury suggests the following revised rule, incorporating 

this proposed change: 

§146.87 (a)( (3) Before and upon installation of the long string casing:

(i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder 

logs, and any other or any suite of logs submitted by the permittee and 

approved by logs the Director before the casing is installed requires for

considering the given geology before the casing is installed; and

*

*

*

The proposed rule also requires unnecessary and duplicative logging with respect to the 

long-string casing.

3. EPA Proposed §146.87(a)( (3) Before and upon installation of the long string 

casing: (ii) A cement bond and variable density log, and a temperature log after the 

casing is set and cemented.

Denbury suggests that the logging options it recommends with respect to surface casing 

also apply for the long-string casing. Thus, the proposed rule should be revised as 

follows:

§146.87(a)(3)(ii) A cement bond and variable density log or other approved 

tool, and or a temperature log after the casing is set and cemented. [see § 

146.12(d)(2)(ii)(C) Criteria and Standards applicable to Class I 

nonhazardous wells: Construction Requirements.]

4. EPA Proposed §146.87(b) The owner or operator must take and submit to the 

Director whole cores or sidewall cores of the injection zone and confining system and 

formation fluid samples from the injection zone(s). The Director may accept cores 

from nearby wells if the owner or operator can demonstrate that core retrieval is not 
27

possible and that such cores are representative of conditions at the well. The Director 

may require the owner or operator to core other formations in the borehole.

Denbury opposes the requirement to collect cores from more than one (1) well within a 

CO2 project. As a practical matter, the majority of the important physical and 

geophysical properties of the injection reservoir, including the particular attributes of the 

confining formations can and are required to be evaluated from logs and other scientific,

reliable measures. A “whole core,” as specified in §146.87(b) is only a very small 

sample of the attributes of a reservoir and a sidewall core, an even smaller sample. The 

former is very expensive to collect, and the latter often not available. Neither is essential 

given the vast amount of data otherwise required, and multiple samples, as proposed by 

the rule, are not reasonable. The unreasonableness of the whole core, sidewall core and 

extra core sampling is evident upon consideration of the sheer volume of physical 

evidence that this provision alone may produce. For example, in Texas there are over 

5000 existing Class II CO2 injection wells. If a small fraction of these wells are 

converted to Class VI CO2 injection wells following the completion of production 

activities, there will be a large universe of cuttings. Where will the regulatory agency 

store this magnitude of cuttings? This may become a particular problem given the total 

number of CO2 sequestration projects that may be proposed. 

Denbury suggests the following:

§146.87(b) At the specific request of the Director and only where core 

retrieval is possible, tThe owner or operator must take and submit to the Director 

a whole cores or sidewall cores of the injection zone and confining system and 

formation fluid samples from the injection zone(s). The Director may accept cores 

from nearby wells if the owner or operator can demonstrate that core retrieval is 

not possible and that such cores are representative of conditions at the well. The 

Director may require the owner or operator to core other formations in the 

borehole.

5. EPA Proposed §146.87(d) At a minimum, the owner or operator must determine 

or calculate the following information concerning the injection and confining zone(s):

(1) Fracture pressure;

(2) Other physical and chemical characteristics of the injection and confining 

zones; and

(3) Physical and chemical characteristics of the formation fluids in the injection 

zone.

Subparagraph (d) of §146.87 provides permittees with a generic list of data that is 

required regarding the injection and confining zone. Fracture pressure is specified. 

Under the circumstances, fracture pressure should only be calculated, rather than 

“determined” as any determination based on techniques beyond mathematical calculation 

will require coring or perforation of the casing, potentially decreasing the mechanical 

integrity of the well and running directly counter to the objective of the proposed rules.
28

With respect to other generic data EPA seeks regarding the injection and confining zones, 

the proposed rule does not to provide sufficient guidance to the permittee on the scope of 

data required on the formation fluids and reservoir zones. Denbury requests clarification 

and specifics both with respect to the nature and type of “physical and chemical 

characteristics” EPA expects a permittee to submit in response to the requirements of 

146.87(d) (2) & (3).

6. EPA Proposed §146.87(f) The owner or operator must provide the Director with 

the opportunity to witness all logging and testing by this subpart. The owner or 

operator must submit a schedule of such activities to the Director 30 days prior to 

conducting the first test and submit any changes to the schedule 30 days prior to the 

next scheduled test.

The agency requires the submission of a proposed logging and testing schedule at least 30 

days in advance of those proposed activities. Although a logging and testing schedule 

certainly can be designed 30 or more days in advance, the actual date that logging is 

performed is usually available only 24 to 48 hours in advance of actual logging 

operations. A mandatory 30 day notice is simply not practical for logging and testing.

Denbury asks that notice requirements in this subpart be adjusted to take into account the 

practical limitations experienced routinely in field operations. Suggested revised 

language is set forth below.

§146.87(f) The owner or operator must provide the Director with the opportunity 

to witness all logging and testing by this subpart. The owner or operator must 

submit a proposed schedule of such activities to the Director at least 30 days 

prior to conducting the first test and submit notice at least 24 hours in advance 

of the conduct of any actual logging and testing. any changes to the schedule 

30 days prior to the next scheduled test.

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 operating injection pressure, unless the Director determines that such 

requirement might harm the integrity of the well. 

EPA’s suggested Mechanical Integrity (“MI”) rule to maintain pressure on the annulus 

exceeding the operating injection pressure will, in most cases, result in an exceedance of 

the burst pressure of the casing. 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 EPA appears to recognize this likelihood and thus allows the 

Director to waive the requirement. However, the rule should not require a questionable 

practice and then permit its waiver. Rather, the practice should only be required if the 
29

Director makes a determination that the conduct of the test will NOT cause a problem. 

The suggested revision is encapsulated below:

(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. If the Director 

determines that such requirement will not harm the integrity of the well, 

Tthe owner or operator must maintain a positive pressure on the annulus a 

pressure that exceeds the operating injection pressure. ., unless the Director 

determines that such requirement might harm the integrity of the well.

2. EPA Proposed §146.88(e) The owner or operator must install and use continuous 

recording devices to monitor: 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 install 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 permitted 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 unnecessary 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 fluids from exiting the wellbore. They are used in off-shore operations 

because of the risk of damage to the wellhead from atmospheric or anthropogenic 

phenomenon, such as a hurricane causing extensive platform damage or a ship colliding 

with a platform. But in an onshore injection system, a down-hole shut-off system 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 down-hole shut-off systems 

should be limited to off-shore operations. 

Furthermore, the requirement to continuously monitor the annulus fluid volume is 

impractical, because it does not provide any 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. Denbury recommends the following:

§146.88(e) The owner or operator must install and use continuous recording 

devices to monitor: 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 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 operator and shut-in off the well 
30

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 operation involves off-shore injection, 

the owner or operator 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 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;

(f) If an down-hole automatic shutdown is triggered or a loss of mechanical 

integrity is discovered, the owner of operator must immediately investigate and 

identify as expeditiously as possible the cause of the shutoff.

*

*

*

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 paragraph (a)(2) of this section:

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

Among the test protocols prescribed by the 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 Director. Conducting a casing inspection log will require the tubing to be 

pulled from a well, and that in turn substantially increases the possibility of 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 

the following edit:

§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 

paragraph (a)(2) of this section:

(3) A casing inspection log, 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 well 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 above, 

Denbury is unaware of a methodology to monitor the actual volume of annular fluid in 
31

the annulus on a continuous basis, and thus seeks agency clarification on this portion of 

the proposed rule. 

2. EPA Proposed §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 meet the minimum standards for 

material strength and performance set forth in § 146.86(b) by:

(1) Placing coupons of the well construction 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 method 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 and 

therefore 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 alternatives approved by the 

Director) will not provide meaningful information regarding the mechanical integrity 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 saturated 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 construction 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 method approved by the Director.

The requirements of this subpart are waived when the carbon dioxide stream 

is dehydrated to meet pipeline specifications.

44For evidence on CO2 corrosiveness in the absence of free water see Don Duttlinger, “Enhanced Recovery 

Intertwines Naturally With CO2 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, CO2 is noncorrosive as long as it is dry. Proving that point, Kinder 

Morgan has hydro-tested the 32-year-old CRC Pipeline built in 1971 to transport CO2. 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 Reef 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).
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 the actual data, or merely an analysis of the pressure fall-off test?

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 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 Director undefined discretion 

to order unlimited and unspecified 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 through appropriate rulemaking procedures and based on an 

adequate factual and scientific record. However, adopting an open-ended power to 

require “any” additional monitoring, at this early stage, 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 costs, creating a barrier to capital formation and discouraging 

geologic sequestration. Accordingly, Denbury recommends deleting this section. 

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 wellbore to be flushed prior to plugging and thus it 

is unnecessary to use cement “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 type and grade and quantity of material 

to be used in plugging. The material must be compatible with the carbon dioxide 

stream;

I. § 146.93 Post-injection site care and site closure.

The proposed rule establishes a 50 year default period for post-injection site care. There 

is, however, no factual or scientific basis for such an extensive period. Under EPA’s 

Resource Conservation and Recovery Act rules, which regulate the disposal of hazardous 
33

wastes, post closure care is limited to 30 years.45 Defaulting to an excessively long 

period will increase costs and introduce greater regulatory uncertainty, which will 

discourage capital formation around CO2 sequestration. A more prudent 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 circumstances warrant a longer post-injection 

site care period. 

Additionally, the proposed rule’s 50 year default post 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 incentive 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 site care rules be reconfigured to require a more 

limited mandatory post-injection site care timeframe, and to allow for closure at the end 

of that period unless the Director affirmatively acts to extend the post-injection site care 

period. 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 comply 

with a plan for post-injection 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 application to be approved 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 site closure as demonstrated in the area of 

review evaluation required under § 146.84(b);

(iii) A description of post-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, owners or operators of Class VI wells 

must either submit an amended post-injection site care and site closure plan or 

demonstrate to the Director through monitoring data and modeling results that no 

amendment to the plan is needed.

(4) The owner or operator may modify and resubmit the post-injection 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 monitor 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 continue 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 sequestration 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 geologic sequestration project no longer poses an endangerment to USDWs, 

the Director may approve an amendment to the post injection site care and site 

closure plan to reduce the frequency of monitoring or may authorize 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 closure, the owner or operator must submit to the Director a 

demonstration, based on monitoring and other site specific data, that the carbon 

dioxide plume and pressure front have stabilized and that no additional 

monitoring 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 geological 

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 

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 submittal of the data required under 

subparagraph (3) above the Director fails 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 

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 any changes have been made to the original post-injection 

site care and site closure plan, the owner or operator must also provide the revised 

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 operator 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 operator must submit a site closure report within 90 days that 
35

must thereafter be retained at a location designated by the Director. The report 

must include:

(1) Documentation of appropriate injection and monitoring 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 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 Administrator of the 

appropriate EPA Regional Office;

(2) Documentation of appropriate notification and information to such 

State, local and tribal authorities as have authority over drilling activities to 

enable such State and local authorities to impose appropriate conditions on 

subsequent drilling activities that may penetrate the injection and confining 

zone(s); and

(3) Records reflecting the nature, composition and volume of the carbon 

dioxide stream.

(f) Each owner or operator of a Class 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 perpetuity provide any potential purchaser of the 

property the following information:

(1) The fact that land has been used to sequester carbon dioxide;

(2) The name of the State agency, local authority, and/or tribe with which 

the survey plat was filed, 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 the post-injection site care period. The owner or operator 

must deliver the 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.
Letter ID: 0215 

Commenter: Ronald Evans 

Organization: Denbury Resources, 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 addition to existing injection and incidental 

storage of CO2 in enhanced oil or gas recovery operations ("EOR" or "EGR," 

respectively)) through Class II wells. In many respects, the Proposed Rule 

appears well-suited to advance that objective and EPA deserves credit for having 

developed a comprehensive approach to a complex set of issues. In other 

respects, however, the Proposed Rule appears to misapprehend certain core facts 

relating to the physical properties and behavior of CO2 in some underground 

formations, the scale of existing CO2 storage operations 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 protection of underground sources 

of drinking water ("USDWs") and a few that would even prove counterproductive. 

[1] See generally Regulating Greenhouse Gas 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 CO2 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). 

Individual Response: EPA disagrees that any of the requirements in the GS rule are 

unnecessary. Rather, the GS regulation tailors the UIC requirements to address the unique issues 

1
associated with large-scale GS, including large injection volumes, the relative buoyancy of CO2, 

its corrosivity in the presence of water, the potential presence of impurities in captured CO2, and 

its mobility within subsurface geologic formations. 

The Agency agrees that GS is a key climate change mitigation technology that is part of a 

portfolio of options that could be deployed to reduce CO2 emissions. Other options include 

efficiency improvements and the use of alternative fuels and renewable 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 applies to owners or operators 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 injection 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 time 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 Class 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 requirements 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 believes 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 constructed or brought online. Comments related to the 

economics of Class II EOR projects transitioning to Class VI projects is outside the scope of this 

rulemaking. The purpose of this rule is to ensure that GS is conducted in a manner that is 

protective of USDWs from endangerment. 

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

will assist Directors in determining whether an injection project should be transitioned from 

Class II, where the primary purpose is oil and gas production, to Class VI, where the primary 

purpose is long-term storage of large volumes of CO2. The guidance describes the methods 

available for the Director to determine changes in risk to USDWs from projects, and how the 

2
Director may determine whether a project should be regulated within the Class II or Class VI 

UIC program. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. For more information, please 

see the discussion on transition of Class II wells 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 storage [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 addressing 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 under the UNFCCC’s Clean Development 

Mechanism (available at http://cdm.unfccc.int/about/ccs/index.html) (last 

visited December 2, 2008). The terms "sequestration" and "storage" are used 

interchangeably in these comments. 

Individual Response: EPA disagrees that the GS rule does not provide commensurate 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 acknowledges that the Class VI requirements have 

associated costs beyond baseline (Class I industrial wells) costs, and believes these costs are 

necessary and appropriate to address the unique challenges posed by large-scale GS, including 

large injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, 

the potential presence of impurities in captured CO2, and its mobility within subsurface geologic 

formations. 

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 risk 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 requirements would allow owners or 

operators to diminish the integrity of a GS site. EPA recognizes that injecting large volumes of 

3
CO2 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 potential impurities in the CO2 stream. In addition, EPA expects the 

tailored permitting, siting, construction, operation, monitoring, and post-injection site care 

requirements in the GS rule to prevent leakage from injection formations and protect USDWs. 

EPA believes that building upon the existing UIC requirements (e.g., Class I and Class II well 

requirements) to develop the Class VI GS regulation provides a protective foundation for 

ensuring protection of USDWs that is based on successful field experience and lessons learned 

about CO2 injection in other applications. Class I well owners or operators have experience with 

site characterization, well construction, and monitoring procedures and technologies that are 

applicable to Class VI wells. Class II ER well operators have experience with managing the 

unique properties of CO2. To successfully flood a hydrocarbon field with CO2 during an ER 

operation, the behavior of injected CO2 must be well understood. 

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 unnecessary and costly requirements in the 

Proposed Rule would discourage, or even foreclose, the conversion of existing 

Class II EOR wells to Class VI geologic sequestration wells. This 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 governments worldwide believe that it must 

play in any successful strategy for reducing atmospheric concentrations of CO2. 

This is important because it means that the EPA may - and indeed, must - balance 

objectives that pull at times in competing directions. In other words, if the 

EPA’s primary objective is to reduce CO2 emissions and if CCS is an essential 

component of a CO2 reduction strategy, then the rules governing CO2 injection 

and storage must be crafted in such a way as to advance the primary objective of 

reducing GHG emissions. 

New rules for CO2 sequestration that are too risky or too costly for widespread 

use will work against this primary overall objective of reducing GHG emissions. 

Absent a broader legal foundation than the SDWA alone, however, the EPA could 

conceivably find itself required to impose 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 purpose 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 foundation for the new 

sequestration rules. 

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

4
Class II EOR wells to Class VI wells are unnecessary. 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 wells were engineered and constructed to meet the requirements 

at §146.86(a) and ensure protection of USDWs, in lieu of requirements at §§146.86(b) and 

146.87(a). 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 costs are expected to be a small 

component of total CCS project costs. EPA estimates that the GS rule requirements amount to 

approximately two percent of the total CCS project 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 injection 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 suggested changes to the proposed regulatory 

text that may help EPA accomplish its stated objectives. Before undertaking that 

section-by-section analysis, however, we first 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 based 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 well converted to use for Class VI CO2 

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 existing EOR sites would complement the 

more extensive rules to govern CO2 injections 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 site 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 sequestration because they have proven 

5
traps 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 anticipated 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: Geologic CO2 Sequestration Technology and 

Cost Analysis (June 2008) at 2 (hereafter "EPA Technology and Cost 

Analysis").[FN5] The same point was made 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 likely to be injected into saline 

formations over the long term, it is anticipated that, given the 

experience and the availability 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 material quantities of CO2 are captured 

from coal-fired electricity generating facilities.[FN6] In addition, much of the 

actual research in examining the not expected for several years,[FN7] and EPA’s 

rules may well need to be modified once the results of those extensive research 

projects are obtained. 

Under the existing UIC rules for Class II wells, however, CO2 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 operations to the incremental storage of 

CO2 captured from industrial or power plant sources once the oil production 

operations have ended. It is true that these sites would not be adequate to 

accommodate all of the CO2 that would be captured if such capture technology 

were deployed on all new power plants. But 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 years.[FN9] Hence 

what is relevant here is that existing EOR-focused sites will be generally 

adequate and available to accommodate 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 missing an opportunity to craft a practical 

transitional pathway that builds on the large scale CO2 injection and storage 

6
operations that are incidental to existing EOR operations to incremental storage 

of CO2 that could begin following termination of a given EOR operation. EPA 

should consider such a transitional pathway from incidental to incremental 

storage at existing well-defined sites with existing CO2 handling facilities as 

a supplemental or complementary approach to the Proposed Rules. 

[4] The estimate of 44 million metric tonnes per year (as of 2007) is contained 

among the Technical Supporting documents referenced in the Proposed Rule. See 

Meyer, "Summary of Carbon Dioxide Enhanced Oil Recovery (CO2 EOR) Injection Well 

Technology," (EPA Document Identification: 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 injections of 0.044 GMT) (hereafter "Meyer"). 

While the Meyer document is not available from regulations.gov, it is published 

on the Ground Water Protection Council’s website at: 

http://www.gwpc.org/e-library/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/fdmspublic/ContentViewer?objectId= 

09000064806418c4&disposition=attach ment&contentType=pdf (last visited November 

10, 2008). 

[6] Transactions to purchase CO2 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 CO2" (November 8, 2006); Press 

Release, Denbury Resources, Inc. "Denbury Signs Agreement to Purchase Additional 

Manufactured CO2" (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) to produce hydrogen-rich synthesis gas for 

power generation while capturing approximately 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 research projects on geologic storage 

of CO2 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 recovery 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. 

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 injections 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 Sequestration 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 373.1 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 CO2 cumulatively over the next 25 years). This suggests average CO2 

injections from power plants of approximately 14.92 million metric tonnes per 

year over the next 25 years, or roughly 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 Support Document: Geologic CO2 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 projection for CO2 sequestration for twenty-five year period 

2012-2036). 

Individual Response: The final Class VI regulations require that any owner or operator 

injecting CO2 for the primary purpose of long term storage obtain a Class VI permit with some 

special consideration for the fact that they are transitioning from a well not originally designed to 

meet Class VI requirements. The Director has the authority to determine at what point a Class VI 

permit is required for those projects that are transitioning from the primary purpose of EOR to 

long term storage of CO2. The final regulation provides a set of technical factors for the Director 

to evaluate in making this determination, at §144.19. EPA believes that this approach provides 

sufficient protection of USDWs when there is an increased risk to USDWs as compared to 

traditional Class II operations while allowing for site-specific flexibility. 

EPA clarifies that injection 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 meets the standards in 

§146.86(a). EPA is allowing the construction of Class II EOR wells to be grandfathered per 

§146.81(c), provided the owner or operator can demonstrate to the Director that the wells were 

engineered and constructed to meet the requirements at §146.86(a) and ensure protection of 

USDWs from endangerment. 

EPA disagrees that the rule needs to address a situation where reservoirs converted for GS would 

return to EOR production. EPA believes that pressure changes in the reservoir as a result of 

injection of high volumes of CO2 for GS would make future use of the reservoir for EOR 

unlikely. 

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

8
will assist Directors in determining whether an injection project should be transitioned from 

Class II, where the primary purpose is oil and gas production, to Class VI, where the primary 

purpose is long-term storage of large volumes of CO2. The guidance describes recommended 

methods the Director may use to evaluate changes in risk to USDWs from projects, and how the 

Director may determine whether a project should be regulated within the Class II or Class VI 

UIC program. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. For more information, please 

see the discussion on transition of Class II wells 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 injection 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 addressed in the near term to allow for 

incremental storage of CO2 in formations where very large quantities 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 adopted in place of the current Proposed 

Rule that offers a limited transition mechanism for Class II wells or as an 

optional alternative. It should of course include verification, 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 results of ongoing research and the pace of 

deployment of capture technology for electricity power plants become better 

known. 

Accordingly, Denbury urges EPA to better recognize the fruits of existing 

experience with injection and storage of large volumes of CO2 that are 

necessarily incidental to EOR operations. That existing experience is 

particularly important because it suggests strongly that the initial CO2 

injections for geologic storage 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 industry experience will necessarily apply 

to the movement of CO2 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 CO2 plumes in such formations. Nonetheless, where 

the CO2 has already been injected in previously defined reservoirs using 

9
approved well construction techniques and permitted by the proper state 

authorities, it should be possible to continue 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 regulations require that any owner or 

operator injecting CO2 for the primary purpose of long term storage obtain a Class VI permit 

with some special consideration for the fact that they are transitioning from a well not originally 

designed to meet Class VI requirements. The Director has the authority to determine at what 

point a Class VI permit is required for those projects that are transitioning from the primary 

purpose of EOR to long term storage of CO2. The final regulation provides a set of technical 

factors for the Director to evaluate in making this determination, at §144.19. EPA believes that 

this approach provides sufficient protection of USDWs when there is an increased risk to 

USDWs as compared to traditional Class II operations while allowing for site-specific flexibility. 

EPA clarifies that injection 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 meets the standards in 

§146.86(a). EPA is allowing the construction of Class II EOR wells to be grandfathered per 

§146.81(c), provided the owner or operator can demonstrate to the Director that the wells were 

engineered and constructed to meet the requirements at §146.86(a) and ensure protection of 

USDWs from endangerment. 

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

will assist Directors in determining whether an injection project should be transitioned from 

Class II, where the primary purpose is oil and gas production, to Class VI, where the primary 

purpose is long-term storage of large volumes of CO2. The guidance describes recommended 

methods the Director may use to evaluate changes in risk to USDWs from projects, and how the 

Director may determine whether a project should be regulated within the Class II or Class VI 

UIC program. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. For more information, please 

see the discussion on transition of Class II wells 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. Circuit has famously - and repeatedly - 

observed that there are some issues encountered 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 during 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. According to the documents in the current 

10
record, state permitting authorities have issued permits for approximately 

13,000 Class II wells to inject CO2 for EOR 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 injections into well-defined oil and gas 

bearing formations, rather than saline formations, many of the operational 

lessons learned relate directly to appropriate well construction requirements 

for CO2 injection wells, corrosion management for injection and production 

wells, as well as pipelines and associated CO2 handling facilities. We 

respectfully urge EPA to give greater weight to that extensive real-world 

experience than currently given under the Proposed Rule. 

The NOPR appears to downplay such actual 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" nature of CO2;[FN13] 

(b) the large scale of CO2 injections anticipated to be captured from coal-fired 

power plants as compared to CO2 injections for EOR purposes;[FN14] and 

(c) the corrosivity of CO2 in the presence of free water.[FN15] 

The Proposed Rule thus states that the regulatory alternative selected was 

chosen "because of the volumes of CO2 being anticipated for long-term storage, 

the buoyant and viscous nature of the injectate, 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"; rather it is simply denser than some 

underground gases, fluids or liquids, while less dense than others. Such 

relative differentials in density do not create an upward "force" as suggested 

by the NOPR’s definition. 

The preamble to the Proposed Rule makes very clear that the changes to the UIC 

program for CO2 sequestration are based on the assertion that CO2 is 

"buoyant."[FN16] This is simply incorrect. CO2 is a non-explosive, nonflammable, non-toxic gas that possesses different physical properties than some 

other injectates. These physical properties do not include any special buoyancy 

characteristics or properties. Rather, CO2 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 relative densities of the various fluids or 

gases that are in the reservoir. The various materials will simply segregate 

based on the relative densities of the fluids 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 fluids within the system. 

11
For example, if CO2 is injected in a system 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 contains natural gas (i.e., methane), the CO2 

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 become "buoyant" as 

defined by the Proposed Rule or exerts any incremental "upward force." Nor does 

it mean that CO2 acquires some special downward force. It simply means that 

natural gas is relatively less dense than the CO2 and hence the two substances 

will tend to separate with the natural gas above the CO2. To reiterate: the 

relative depths, pressures and fluids within 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 supporting documents for the Proposed Rule. 

For example, the Vulnerability Evaluation Framework [FN17] explains that: 

Supercritical CO2 is less dense and more buoyant than oil and 30% to 50% 

more buoyant than saltwater. As a result, 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 reservoirs. As temperature increases, the 

density of supercritical CO2 decreases at a given pressure, but 

increases with increasing pressure at a given temperature. Similarly, 

the viscosity of supercritical CO2 decreases with increasing temperature 

at a given pressure, but increases with increasing pressure at a given 

temperature. As temperature and pressure increase with subsurface depth, 

the density and viscosity of supercritical CO2 injected will be 

determined by the specific pressure and temperature conditions. Finally, 

when CO2 dissolves, it shares the physical properties of the substrate 

(e.g., saltwater) and no longer behaves independently. 

The Proposed Rule does not incorporate this 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 which it is fully or partially 

immersed, caused by differences in pressure or density. 

73 Fed. Reg. at 43,493 (emphasis added). This use of the word "force" is 

scientifically inaccurate and generates connotations that there are additional 

forces created when CO2 is injected into the subsurface for sequestration. This 

12
is not the case, however, as there are no additional or different forces 

associated with CO2 injections than there are with the injection of any other 

fluid or gas. The injection of any fluid into the subsurface creates a transient 

pressure wave that is greater at the injection site and diminishes significantly 

at positions located away from the injection 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 focus 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 bottom 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 endow the CO2 with any buoyant force, 

however. The issue is not "buoyancy," but merely 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 injectate" is cited as a key reason why 

"...EPA is proposing changes to the existing UIC approach or requirements in 

several program areas..." 73 Fed. Reg. 43,504. This misunderstanding of how 

injected CO2 behaves underground is repeated at multiple points in Sections 1, 

2, 3, 4, 5 and 8.[FN18] The fact that the significant new regulatory regime set 

forth in the Proposed Rule is based to such a great extent on factually and 

technically erroneous information 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 should lead EPA to find the existing UIC 

methodologies and rules generally sufficient to address CO2 injections for 

geologic storage in oil and gas bearing formations. In other words, Class II 

regulations and requirements should be used with the addition of requirements 

for long term monitoring if, for example, 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 requirements have proven successful in 

protecting underground sources of drinking water for almost 40 years and thus 

modifications or additions are more appropriate than establishing a completely 

new well classification. 

[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 Levanthal, J.). Judge Levanthal’s opinion 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) and Maryland People's Counsel 

13
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] 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 EPA-HQ-OW-2008-0390- 

0084.pdf) (available also from the Ground Water Protection Council’s website at: 

http://www.gwpc.org/elibrary/ e-library_documents/elibrary_documents_co2/Argonne%20Report%20CO2%20Resources.pdf (last visited 

November 10, 2008) at 8 (Table 3) (listing CO2 injection wells by state and by 

UIC well class)). The number of active CO2 injection wells is also 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 CO2 

injections for geologic storage. 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 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 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 (defining buoyancy as "[u]pward force on 

one phase (e.g., a fluid) produced by the surrounding fluid (e.g., a liquid 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 CO2 rises in the formation 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 properties 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 mixed with water); at 43,505 (stating that 

"buoyancy of CO2 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 CO2"); id. (stating 

that computational models used to delineate the area of review consider inter 

14
alia the "buoyant nature" of the injected CO2); at 43,509 (basing proposed 

enhancement to deep well construction procedures "[d]ue to the buoyancy of CO2" 

in order to provide additional barriers to CO2 leakage outside of the injection 

zone); at 43,512 ("buoyancy of CO2" 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 CO2 storage to address the 

"unique properties of CO2, specifically its buoyancy and potential 

corrosivity"); id. (same, referencing need for tailored testing requirements 

"because of the buoyant and corrosive properties" of the CO2 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 43,519 (stating that area over which CO2 will spread is 

likely to be larger than for existing well classes "[g]iven the buoyancy of CO2, 

viscosity, and large injection volumes" associated with geologic storage of 

CO2); and at 43,528 (stating that current 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 requirements in the final GS 

regulation. For example, the volume of CO2 anticipated to be injected in Class VI wells is 

significantly greater than for Class II wells. Reservoir pressure conditions will be different, with 

Class VI injection operations involving large volumes of CO2 and likely having higher pressures 

within their storage formations than Class II ER projects. Therefore, Class VI GS reservoir 

pressures will increase more in comparison to Class II ER during the injection phase of the GS 

project. 

EPA disagrees with the commenter that the buoyancy 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 movement of CO2, or "buoyancy." The buoyancy of 

CO2 is unique compared to many other injected 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 formation as early as three years after injection began. Data and 

information from the Sleipner project show that the injected CO2 migrated 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 geologic confining zone is not present to stop 

15
upward movement or if there are artificial penetrations 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 addition to the information cited in the preamble to 

the proposed rule, EPA published a Notice of Data Availability and Request for Comment on 

August 31, 2009 (74 FR 44802), in which the Agency described the results of research at three 

DOE partnership sites: the Escatawpa, Mississippi project; the Aneth Field project in Paradox 

Basin, Southeast Utah; and the Pump Canyon Site, New Mexico. 

EPA is using an adaptive approach to regulating GS. The Agency plans to collect and review 

data every six years on GS projects to determine whether the appropriate amount and types of 

information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

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, the scale of CO2 injections anticipated 

to be captured from coal-fired power will be far less - not greater - than the 

scale of existing CO2 injection operations for many years and therefore does not 

justify the proposed new regulations at this time. 

The second basis for the Proposed Rule’s conclusion that CO2 injections for 

geologic storage are "unique" is the statement that the scale of these 

injections will be on a scale that is much larger than other types of UIC 

injection operations.[FN19] This 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 NOPR itself recognizes, this is only about 

half the quantity of CO2 that has already 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 annual 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 - the equivalent of approximately 13.4 

million metric tonnes -- the great majority of which was injected for EOR 

operations.[FN22] In other words, the scale of operations of this one company - 

which is not the largest participant in the EOR industry - is essentially the 

same by itself as EPA’s projected average injection rate for geologic storage 

for the entire nation of 14 million tonnes per year over the next 25 years (as 

16
published 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 nation’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 power plants) is expected to remain 

the case for decades. It is only in some distant future that injections of 

powerplant CO2 are anticipated to approach 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 not 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 captured 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 less than 5 percent -- one-twentieth -- 

the level of current Class II CO2 injections (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 pressure front of a full-scale GS project 

will be "much larger" than for CO2 injections for EOR purposes; the facts are 

quite the reverse: The scale of current CO2 injections through existing Class II 

wells is already vastly larger than the scale 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 are not appropriate 

for long term sequestration, especially when dealing with deep saline formations 

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 CO2 

into saline formations, as a framework for allowing the transition of the 

existing and planned universe of CO2 wells from EOR operations to long term 

geologic sequestration operations. Further 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 that point, such rules would properly be 

based on additional years of research regarding the movement of a CO2 plume in a 

17
saline formation, the experience of the state Directors with monitoring and 

remediation activities, etc. 

[19] See, e.g., 73 Fed. Reg. 43,506 (stating 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); 

73 Fed. Reg. at 43,518 (requirement to address 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 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 recovery operations, "which currently inject CO2 on a 

relatively small scale"). 

[20] 73 Fed. Reg. at 43,527. This estimate is within the range of other 

published estimates. For example, the IPCC 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 separately 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 Carbon 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 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/elibrary/ 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_August2007.pdf (last visited 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. 

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

[25] The estimate of 3 million metric tonnes 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 Future 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. 

18
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 identified unique challenges 

posed by large-scale GS, including large injection volumes, the relative buoyancy of CO2, its 

corrosivity in the presence of water, the potential presence of impurities in captured CO2, and its 

mobility within subsurface geologic formations 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 regulating GS. The Agency plans to collect and review 

data every six years on GS projects to determine whether the appropriate amount and types of 

information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

In response to the comment about the anticipated 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) indicate that CCS has the potential to play a significant role in 

climate change mitigation scenarios. For example, 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/economicanalyses.html#hr2454). Under any approach 

to address GHG emissions, CCS offers great potential for significant 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 corrosivity of CO2, which is not at all 

corrosive except in the presence of free water. 

The third basis for the Proposed Rule is the potential corrosivity of CO2.[FN26] 

The Proposed Rule specifically seeks comment regarding requirements for 

degradation-resistant well construction materials, such as acid-resistant 

cements and corrosion-resistant casing. The NOPR correctly states that CO2 mixed 

with water will form carbonic acid (H2CO3) and that carbonic acid is corrosive 

of cement -- a fact that has long been taken into account in existing permitting 

procedures and industry practices. However, the preamble to the Proposed Rule 

appears to overstate the corrosivity of CO2 under actual geologic storage 

conditions. For example, the NOPR references (73 Fed. at 43,510) the actual 

field experience and observations from wells that had been exposed to a CO2- 

water environment for 30 years, but then appears to largely dismiss the results 

19
on the grounds that this actual field corrosion experience is "surprisingly" low 

(presumably in light of a referenced laboratory study that found much more rapid 

corrosion than has in fact been experienced).[FN27] In contrast, a study that 

reviewed actual samples exposed to a CO2-water environment for 30 years was 

seemingly dismissed as involving "only limited examples," while the 

contradictory laboratory study was apparently given greater weight.[FN28] 

The Proposed Rule appears to downplay other research publications that conclude 

that conventional Portland-based well cements have been adequate to guard 

against corrosion from CO2 mixed with water. For example, the Proposed Rule 

cites Meyer (2007)[FN29], but doesn’t recognize that Meyer notes that nonPortland cements have not been widely used in CO2 EOR applications, and have 

been applied instead to resist "very severe acid gas (CO2 and H2S) and highly 

corrosive geothermal brine exposure conditions." Meyer (2007), supra, n. 4 at 

18. Dr. Meyer also noted the actual experience from a 52 year old well with 

conventional, Portland-based well cement, that had been exposed to CO2 for 30 

years in EOR operations and no significant wellbore failure had been observed. 

Id. (referencing Carey, et al. 2007).[FN30] Indeed, Carey, et al., concluded 

from the review of actual cement exposed to CO2 for 30 years that "[t]he casing 

was in excellent condition and showed little evidence of corrosion." Carey, et 

al., at 76. While the Portland cement did show evidence of exposure to CO2, the 

structural integrity of the recovered cement core, petrographic observations, 

air permeameter data, and cement bond log indicated that "the cement retained 

its capacity to prevent significant transport of fluid through the cement 

matrix." Id. at 84; see also at 78 ("no obvious evidence for CO2 interaction" in 

the shale caprock); id. (core bond log showed "no evidence of CO2- induced debonding or channel formation at or near the reservoir contact"); id. ("most 

basic observation of the SACROC core" is that the Portland cement at the studied 

well "survived and retained its structural integrity after 30 years in a CO2- 

reservoir environment"). 

Finally, the record here should be supplemented with additional laboratory 

research published after the Proposed Rule, the results of which suggest a rate 

of degradation of Portland cement under conditions mimicking geological 

sequestration that is far less than the study cited in the Proposed Rule. See 

Kutchko, et al. "Rate of CO2 Attack on Class H Well Cement under Geologic 

Sequestration Conditions" (hereafter Kutchko, 2008).[FN31] While the details of 

the research merit careful consideration, and additional research is currently 

underway, the conclusion of this August 2008 research publication is worth 

quoting: 

Based on the alteration process, penetration depths, and rates of 

alteration observed in this study, and on penetration depths observed in 

field samples exposed to CO2 for ~30 years, it is unlikely that 

alteration of these cements via cement matrix diffusion of supercritical 

CO2 or CO2-saturated brine would lead to significant alteration in well 

20
completions that are properly cemented with Class H neat cement after 

decades of exposure to supercritical CO2 or CO2-rich brine. 

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

This research is reinforced by other papers presented at a major international 

conference on greenhouse gas control technologies, the 9th International 

Conference on Greenhouse Gas Control Technologies (hereafter cited as "GHGT-9") 

that we commend to the agency’s attention, including in particular:[FN32] 

- Duguid, "An estimate of the time to degrade the cement sheath in a well exposed 

to carbonated brine," summarizing (at 3-4) recent physical research on cement 

carbonation and describing own research. In sum, Duguid’s recent experiments 

indicate (at 8) that for a well that has good zonal isolation and no pathways for 

flow, "the rate of degradation will be between 30,000 and 700,000 years to 

degrade 25 mm of neat paste in a sandstone reservoir, and possibly longer to 

destroy the cement passing through the cap rock."[FN33] 

- Crow, Williams, Carey, Celia, and Gasda, "Wellbore integrity analysis of a 

natural CO2 producer," at 8 (concluding, inter alia from analysis of 30 year old 

well from a natural CO2 production reservoir that Portland-based cement systems 

"can be used effectively in creating suitable barrier systems for long-term CO2 

storage operations, if good practices are employed during well construction"); 

- Benge, "Improving wellbore seal integrity in CO2 injection wells" (reviewing 

recent research and noting (at 2) that applying the formula developed by BarletGouedard, et al., it would take "several hundred centuries" - tens of thousands of 

years -- to degrade 6 meters of wellbore cement (even assuming a continuous and 

renewable supply of fresh CO2 with no other inhibiting reactions occurring). 

- Aiken, "An Introduction to the IEA GHG International Research Network on 

Wellbore Integrity." The paper reviews the work of the IEA’s International 

Research Network on Wellbore Integrity founded some 4 years ago and noting (at 

1, 6) the importance of analyzing the differences found between laboratory 

experiments and corresponding field findings, and if necessary, designing new 

laboratory experiments to better replicate field conditions. 

A great deal of other original research was presented as well, underlining the 

dynamic nature of research in this area and reinforcing the importance of 

avoiding overly-prescriptive requirements that are unnecessary based on 

experience in the field. 

We concur with the Proposed Rule’s general principle that cement and cement 

additives must be "compatible with the carbon dioxide stream and formation 

fluids" and "of sufficient quality and quantity to maintain integrity over the 

design life" (Section 146.86 (b) (5)). However, we are concerned that the rule 

21
contains prescriptive well construction and monitoring requirements that do not 

appear necessary in light of actual field experience and the more recent 

laboratory research referenced above. At a minimum, the more recent research 

suggests that EPA should defer imposing these additional costly requirements 

pending the fruits of the further field experience and research. 

[26] See 73 Fed. Reg. at 43,503 (design changes are being proposed to address 

mobility "and corrosivity" caused by long term GS of CO2); id., at 43,504 (EPA 

proposing changes "[b]ecause of" the volumes of CO2 being anticipated for longterm storage, the buoyant and viscous nature of the injectate, "and its 

corrosivity when mixed with water"); id. at 43,509 (pointing to the "potentially 

corrosive nature of the injectate" in the design and construction of CO2 GS 

wells and noting that "CO2 mixed with water or impurities (NOX, SOX and H2S) can 

be corrosive to well materials and cements" and expressing concern that 

"conventional" cement formations (e.g. Portland cement) are "potentially 

vulnerable" to acid attack). 

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

[28] Id. ("[a]though the field corrosion looks surprisingly low, these are only 

limited examples. Laboratory studies are conducted under aggressive chemical 

conditions in an attempt to mimic the cumulative effects of long-term exposure 

to CO2-rich formation fluids. Given the high injection rates, long lifespan, and 

potential impurities in GS, careful selection of acid-resistant materials and 

practices may be necessary). 

[29] Meyer, supra, n.4. 

[30] Dr. Meyer references the pre-publication version of Carey, J.W., M. Wigand, 

S.J. Chipera, G. WoldeGabriel, R. Pawar, P.C. Lichtner, S.C. Wehner M.A. Raines 

and G.D. Gutherie Jr., "Analysis and Performance of Oil Well Cement with 30 

Years of CO2 Exposure from the SACROC Unit, West Texas, USA," preprint submitted 

to International Journal of Greenhouse Gas Control, October 18, 2006. The 

citation to the published report is 1 International Journal of Greenhouse Gas 

Control, pages 75-85 (2007). 

[31] Barbara G. Kutchko, Brian R. Strazisar, Gregory V. Lowry, David A. Dzombak, 

and Niels Thaulow, "Rate of CO2 Attack on Class H Well Cement under Geologic 

Sequestration Conditions," Environmental Science and Technology, vol. 42, number 

16 (August 15, 2008), at 6237-42. 

[32] "GHGT-9, 9th International Conference on Greenhouse Gas Control 

Technologies," (November 16-20, 2008) Washington DC (http://mit.edu/ghgt9/) 

(hereafter "GHGT-9 Conference" (organized by MIT in collaboration with the IEA 

Greenhouse Gas R&D Programme (IEA GHG), with major sponsorship from the U.S. 

Department of Energy). All papers presented at the GHGT-9 Conference are 

22
available from the conference website at: http://mit.edu/ghgt9/papers/index.html 

(last visited December 12, 2008) and through the site’s search portal at: 

https://www4.eventsinteractive.com/iea/rs.esp?id=270005&scriptid=sppp1 (last 

visited December 12, 2008). 

[33] It should be noted that these results are quite different than in a 2006 

paper by some of the same researchers which EPA included among the supporting 

materials in this proceeding. Compare A. Duguid, M. Radonjic, R. Bruant, T. 

Mandecki, G. Scherer, and M. Celia "The Effect Of CO2 Sequestration On Oil Well 

Cements" (Document ID: EPA-HQ-OW-2008-0390-0013) (posted by EPA July 25, 2008). 

Individual Response: EPA disagrees that the potential corrosion of well materials and cements 

when exposed to CO2 in the presence of water or other fluids is overstated. While some studies 

of cement performance have shown encouraging results, other information gathered through 

stakeholder workshops, research, and field data provide evidence of chemical alteration and 

suggest a potential for degradation to occur and potentially endanger USDWs. 

Although the laboratory and field studies suggest that corrosion problems may not be severe, 

such problems cannot be conclusively ruled out, and the amount of available data on this topic is 

still limited. Laboratory exploration of cement alteration and degradation is an ongoing research 

area, and field-based studies are very few. There also does not appear to be a clear consensus on 

the corrosion risks for the steel components of injection wells. Given the anticipated long 

lifespan of Class VI wells and the difficulties that would be associated with a corrosion-related 

well failure, EPA believes that the construction requirements at §146.86 are justified. 

EPA has reviewed the study by Meyer (2007) cited by the commenter, along with other 

laboratory and field-based research (Barlet-Gouedard et al., 2006; Kutchko et al., 2007, Carey et 

al., 2007, and Crow et al., 2008) that have shown Portland cement alteration (carbonation) when 

the cement is exposed to CO2. While research indicates that cement alteration occurs, the 

alteration appears not to significantly reduce the integrity or performance of the cement. 

However, under conditions simulating flowing CO2-saturated brine, loss of structural integrity 

(more significant degradation) of cement was found in laboratory studies (Duguid et al. 2005), 

although it is uncertain whether wells in GS operations would be exposed to flowing CO2-

saturated brine. The field-based studies that identified alteration reflect the results of relatively 

few samples from a very small number of wells, and the well material samples may have been 

exposed primarily to dry CO2. Cement degradation and corrosion are a possibility, so the cement 

and cement additives used may need to be acid-resistant to meet the requirement that they are 

compatible with the CO2 stream, formation fluids, and the anticipated injection zone conditions. 

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 other recent research from the GHGT-9 

Conference that is relevant to this rulemaking with regard to the carbon content 

23
of oil that could be produced via CO2 injection of captured CO2 emissions. 

Ferguson, et al. reviewed the net carbon content of oil produced via CO2-based 

EOR, taking into account the storage of residual CO2 that remains stored as a 

normal incident of EOR production operations. The researchers calculated that 

oil produced through injection of captured CO2 emissions would be roughly 70 

percent "carbon free" under current technology. See Ferguson, Nichols, Leeuwen, 

and Kuuskraa, "Storing CO2 with Enhanced Oil Recovery" ("Ferguson, et al. 2008") 

[FN34] The authors estimate that next generation CO2 storage 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 and 2030. This capability of the U.S. 

oil industry to reduce the net carbon content of new oil supplies is an aspect 

of the sequestration debate that is not 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 Conference 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 injecting CO2 to enhance production of oil or gas. Those owners or operators 

that choose to transition from enhanced recovery to GS may do so, provided they meet the 

requirements for Class VI wells. 

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, and 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-Injection 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 phases 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 financial assurance and the sagacity of 

other regulatory proposals. 

24
First, we believe that published and reputable literature suggests that a 50- 

year timeframe for post-injection site care is too long and wholly unrelated to 

the risks associated with geologic storage. For well-sited, characterized, 

operated and managed sites, the risks accumulate during the operational phase, 

but decline as sites move from post-injection 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 unexpected release of carbon dioxide more 

than 10 years after termination of injection 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 -- which is addressed in the proposed rule 

and is not necessary to discuss further here; 2) residual CO2 trapping -- where 

CO2 is trapped by capillary forces in the interstices of the rock formation, a 

process which develops about 10 years after injection; 3) dissolution or 

solubility trapping -- where the CO2 dissolves into the brine found in the 

geological formation and sinks because the 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) mineralization or mineral trapping -- which 

occurs when dissolved CO2 chemically reacts 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 operational 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-injection site care 

timeframe simply does not correlate to the relative risks associated with 

geological storage and the function of geologic trapping mechanisms that limit 

the risk of unexpected releases of CO2 after the termination of injection 

activity. 

Furthermore, other respected models use a much shorter period. For instance, the 

IOGCC Model Rules and Legislation stipulate a 10 year post-injection site care 

period.[FN38] Under the IOGCC Model, the operator of the storage 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 plainly related to the relative risks of 

geologic storage and the geochemical reactions discussed above. Also, in the 

preamble, EPA acknowledges that a 30-year post-closure care period is recognized 

as the industry standard for the injection of hazardous waste.[FN39] 

[35] See Intergovernmental Panel on Climate Change, Special Report on Carbon 

Dioxide Capture and 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, 

25
available at 

http://pangea.stanford.edu/research/bensonlab/presentations/Carbon%20Dioxide%20C 

apture%20and%20St 

orage%20-%20Research%20Pathways%20Progress%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, supra n.2, at 208; see also Benson 2007, 

supra n.35. 

[38] See generally IOGCC, "Storage of Carbon Dioxide in Geologic 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 responsibility is at Model General Rules 

and Regulations, 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 accordance 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. 

Individual Response: EPA agrees that some owners or operators will be able to demonstrate, in 

less than 50 years, that the pressure front and plume no longer pose a risk of endangerment to 

USDWs. However, based on studies, EPA believes that the 50-year default time frame is 

warranted in most cases based on additional review of research studies and reports and 

evaluation of public comments. 

EPA believes that the best way to address all possibilities, while ensuring USDW protection 

from endangerment, is to set a 50 year default post-injection site care timeframe, with flexibility 

to: (1) allow the Director discretion to shorten or lengthen the PISC timeframe during the PISC 

period based on site-specific data, pursuant to requirements at §146.93(b); or (2) afford the 

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-endangerment of USDWs pursuant to requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters¿ concerns, while ensuring USDW protection. 

26
Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA clarifies that, in determining the post-injection site care-timeframe for the proposed 

regulation, EPA reviewed industry reports, existing environmental programs, and initial GS 

research studies. EPA provided a synthesis of pertinent results from GS modeling studies in the 

preamble to the proposed regulation. Further explanation of this analysis was included in an 

EPA-prepared background document that is available in the federal docket, titled 

""Computational Modeling of Underground Injection of Carbon Dioxide for Determination of 

Area-of-Review and Potential Risk to Underground Sources of Drinking Water."" 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 cessation of injection. EPA believes 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 this in the final regulation. 

To the comment about the cost of post-injection site care, EPA does not agree 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 represent a relatively minor component of total 

project cost, and will provide an essential level of protection from endangerment for USDWs. A 

discussion of the costs attributed to monitoring technologies (used during injection and the postinjection site care timeframes) is available in the Technology and Cost Document for the GS 

rule, which is in the federal docket for this rulemaking. EPA believes that it is logical to make 

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

endangered. 

EPA also recognizes the concerns associated with assuring financial responsibility for the long 

time-frames over which post-injection site care will be conducted. However, the Agency believes 

that, in order to protect USDWs from endangerment under the SDWA, operators must 

demonstrate under §146.85 that financial 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 Directors in evaluating financial responsibility 

demonstrations. The guidance describes the types of financial mechanisms that operators may 

choose to use when evaluating the financial responsibility requirements for GS wells and it will 

also include a section on how to estimate costs to support accurate financial responsibility 

demonstrations. The guidance will be available at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

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 Responsibility and Long-Term Care 

Requirements 

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

27
for 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 care and site closure. Undoubtedly 

owners/operators will enter the private sector financial assurance market for 

some period in order to meet this requirement. An uncertain or a 50-year postinjection site care timeframe creates impediments to managing this financial 

responsibility. We believe that both an indeterminate or an exceedingly long 

post-injection site-care period will discourage the development of private 

sector products to address financial responsibility and discourage sequestration 

in general. 

Individual Response: EPA disagrees that the requirements for financial responsibility 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 owner or operator experiences financial difficulties 

throughout the life of the project. See the final rule and preamble for further discussion of EPA's 

final approach to financial responsibility. 

EPA believes that minimum financial responsibility requirements are necessary to hold well 

owners or operators accountable for the safe operation and proper site closure of the well in order 

to protect USDWs while also avoiding expense and risk to the public. EPA adds that the purpose 

of the GS rule is not to encourage the use of GS; rather, the purpose of the GS rule is to ensure 

that, where GS is deployed, it is conducted in a manner that protects USDWs from 

endangerment. 

Letter ID: 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 the 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 science, unnecessary to protect 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 

supported by the relative risks involved and 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 site care timeframe of 50 years is 

excessive in most cases or arbitrary. EPA proposed a default post-injection site care timeframe of 

50 years based on a review of research studies, industry reports, and existing environmental 

28
programs. This analysis was included in an EPA-prepared background document that is available 

in the federal docket, titled "Computational Modeling of Underground Injection of Carbon 

Dioxide for Determination of Area-of-Review and Potential Risk to Underground Sources of 

Drinking Water." EPA assessed various default timeframes based on additional review of 

research studies and evaluation of public comments. While numerous commenters suggested that 

EPA shorten the monitoring timeframe, none of the commenters provided sufficient data or other 

evidence to warrant a change in the proposed timeframe. While the 10- or 30-year timeframe 

suggested by some of these commenters may be within the timeframe suggested in some studies, 

EPA believes that the potential risks of endangering USDWs will likely not decline within these 

timeframes and available data, including data submitted by commenters, do not support a 

different default timeframe. However, EPA recognizes that alternative timeframes may be 

appropriate under limited, specific circumstances. 

For this reason, the GS rule offers owners or operators flexibility regarding the duration of the 

PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC 

timeframe during the post-injection period based on site-specific data, pursuant to requirements 

at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator 

to demonstrate, during the permitting process based on substantial data, that an alternative PISC 

timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to 

requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in all but a limited number of cases. This default 50 

year post-injection site care timeframe represents a reasonable and protective monitoring period 

based on a review of research studies, industry reports, and existing environmental programs, 

and evaluation of public comments. 

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 agree 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 represent a relatively minor component of total 

project cost, and will provide an essential level of protection from endangerment for USDWs. A 

discussion of the costs attributed to monitoring technologies (used during injection and the postinjection site care timeframes) is available in the Technology and Cost Document for the GS 

rule, which is in the federal docket for this rulemaking. EPA believes that it is logical to make 

29
use 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 issues (seeking comment) 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: III. ANY FINAL RULE MUST CLEARLY ADDRESS POTENTIAL EXPOSURE 

UNDER RCRA AND 

CERCLA 

EPA can and should simultaneously 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 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 carbon capture and storage in order to 

address broader environmental protection concerns. 

If EPA is going to address these broader concerns by establishing a framework 

for the injection and sequestration 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 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 liability. When Congress passed CERCLA, it imposed joint and 

several liability on landowners, transporters, and generators of hazardous 

substances and it made that liability retroactive. Most recently, the Supreme 

Court, in Massachusetts v. EPA, 549 U.S. 497 (2007), recognized that the Clean 

Air Act ("CAA"), with its "capacious" definition of air pollutant, could be used 

to regulate substances (in this case, CO2) which Congress appeared to not intend 

to regulate and whose regulation under many provisions of the CAA (i.e., the 

NAAQS) is awkward at best. One lesson from these statutes and the Courts’ 

interpretation is that regulated industry cannot underestimate its potential 

liability for pollution, irrespective of its compliance with current regulations 

and irrespective of the magnitude of its role in the waste disposal 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 regulatory clarity as to compliance obligations 

and potential for liability. 

[40] Comprehensive Environmental Response, 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 regulatory schemes are undesirable. EPA 

received many comments regarding the applicability of the RCRA regulations and statute to CO2 

streams that are geologically sequestered under the final Class VI UIC well requirements. As a 

result, EPA has decided to initiate a separate proposed rulemaking 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 part 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 proposed 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 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 sulfuric acid). Whether such substances may result in CERCLA liability 

from a sequestration facility 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” (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 issues (seeking comment) 

Comment: A. EPA Should Ensure Clarity Regarding 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 that 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 whether 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 resolve this issue could inhibit permitting 

of wells under the proposed new Class VI regime. 

31
The Proposed Rule asserts that its design changes are meant to address the 

mobility and corrosivity caused by long term geologic sequestration of CO2, and 

not the long term storage of hazardous wastes. EPA seeks comment on its 

definition of "carbon dioxide stream" to exclude hazardous wastes: 

"Carbon dioxide stream means carbon dioxide that has been captured from 

an emission source (e.g., a power plant), plus incidental associated 

substances derived from the source materials and the capture process, 

and any substances added to the stream to enable or improve the 

injection process. This subpart does 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 previously excluded certain substances 

from coverage under 40 C.F.R. § 261.2. CO2 is not excluded under this section, 

but it is also not specifically included as a hazardous 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 stringent handling, storage, and disposal procedures above what 

would be required by the Proposed Rule (except 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 Class 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 comment in the proposed rule. RCRA defines 

solid waste to include "discarded material, including solid, liquid, semi-solid, 

or contained gaseous material resulting from industrial . . . 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 use in EOR or EGR activities should be 

explicitly excluded as it would 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 subject to these provisions. 

Using authority granted by RCRA § 3001, EPA has exempted from RCRA’s definition 

of solid waste certain low-toxicity wastes that exist in high-volumes, including 

domestic sewage, mining wastes, and certain 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 

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

Even if EPA decides not to exclude or exempt 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, concentration, 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 the spectre that the injection of CO2 in 

conjunction with hazardous components could 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 associated with the exploration, development, 

and production of crude oil, natural gas, and geothermal energy. See Regulatory 

Determination 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 

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, perhaps by anti-CCS activists, and the 

maintenance of which would irreversibly chill CCS projects. 

Individual Response: EPA received many comments regarding the applicability of the RCRA 

regulations and statute to CO2 streams that are geologically sequestered under the final Class VI 

UIC well requirements. As a result, EPA has decided to initiate a separate proposed rulemaking 

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 part 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 proposed 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. 

The final GS rule retains the definition of a CO2 stream as proposed. The GS regulation applies 

to injection of CO2 for the purpose of GS, regardless of the source of the CO2. It is beyond the 

scope of the GS rule and the UIC Program’s authority to require or set standards for upstream 

generators of CO2 or purification facilities. For purposes of GS, the UIC program’s authority 

under the SDWA is limited to ensuring that GS projects are sited, constructed, operated, and 

closed in a manner that protects USDWs. EPA adds that promoting the use of GS is outside the 

scope of the GS rule. 

33
Letter 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 Geologic 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 contain hazardous substances or that the 

CO2 stream could react with groundwater to produce hazardous substances, and 

concludes that "whether or not there is a ‘hazardous substance’ that may result 

in CERCLA liability from a sequestration facility depends entirely 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 "federally permitted releases," including 

releases in compliance 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 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 for CERCLA liability will deter efforts 

to develop CCS projects. Under CERCLA, private parties or government entities 

can sue to recover "response costs" associated with any "release" from a 

"facility" of a "hazardous substance." Liability is retroactive, joint and 

several, and falls upon both current and past owners of facilities, and on those 

who generated or transported those "hazardous substances." 42 U.S.C. § 9607(a). 

The broad nature of CERCLA liability makes it a vigorous 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 CO2 is non-toxic at low concentrations 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 envisioned when it enacted CERCLA, the 

definition that Congress included in the statute is reminiscent of the 

"capacious" definition of "air pollutant" that the Supreme 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 showed no intent to do when it enacted 

the Clean Air Act. To avoid a similar outcome here, the EPA should define that 

the injection of CO2 under a Class VI permit constitutes a "federally permitted 

release." 

34
EPA’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 United 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 exemption"). In 1988, it stated in the 

preamble to a proposed rule that would have 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." Reporting 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 CERCLA cleanup liability under section 9607. 

To be sure, this would be a narrow exemption, 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 position 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 were not expressly 

permitted in the various permits, which exceeded the 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 recognize the 

applicability of the FPR exemption without significantly revising its position 

on the FPR. 

Yet another basis on which to exclude injected 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 purchase anthropogenic CO2 from multiple 

sources. While the price of the CO2 varies, it has a significant value to 

Denbury and other EOR operators. As discussed above, the most realistic path for 

storage of CO2 over the next several years is incidentally in oil and gas 

bearing formations. Thus, captured anthropogenic CO2 will be a commodity for 

purposes of EOR for many years.[FN42] Further, 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 CERCLA’s coverage. 

35
To be sure, EPA does not have the authority to protect CCS operations from 

liability under state statutes and common 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 engaging 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 purposes 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 sulfuric acid). Whether such substances may result in CERCLA 

liability from a sequestration facility 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 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. EPA is promulgating this rule under the authority of SDWA. To the 

extent that the commenter is seeking interpretation of CERCLA and its related provisions, such 

interpretations are outside the 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 remedial response is necessary. Although EPA anticipates that the need 

for emergency or remedial actions at GS sites will be rare, the GS rule requires, at §146.94, that 

emergency and remedial response plans be developed and updated to address such events and 

that owners or operators demonstrate that financial resources are set aside to implement the plans 

if necessary, per §146.85. 

EPA clarifies that, while the Administrator reserves 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 regulation 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 forth the information which the owner or 

operator must submit to the Director in order 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 prior to well drilling (applicants will 

not drill the well until it has been approved, otherwise they risk drilling an 

unusable well). Still other data can only be obtained after injection activities 

have been initiated. Post-drilling and post-injection data should not be 

required as part of the application process but instead should be considered 

confirmatory data that may be submitted after 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 initial permit application, and only those 

data that may be reasonably obtained prior 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 available 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 information to be submitted before operation 

of the well is authorized (at §146.82(c)). 

EPA believes that this revision 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 injection well classes, which could help avoid 

confusion about how to meet the permitting requirements 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 modifications and additions that 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/edits 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 cross sections 

indicating the general 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, where known; 

37
So long as the Applicant proposes to inject CO2 below the lowermost USDW, as 

proposed under the rule, there is no justification to require maps and 

stratigraphic cross sections for the entire extent of those USDWs above the 

lowermost USDW, although mapping and stratigraphic cross sections in the 

immediate vicinity of the proposed injection 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 subparagraph (f) should be modified as 

follows: 

(f) Maps and stratigraphic 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 sections for the entire extent of those USDWs above the lowermost 

USDW. EPA believes that a thorough understanding of the hydrogeologic conditions of all 

USDWs in the AoR is necessary. EPA clarifies that §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/edits 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 results 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 subparts (l), (r) and (s) of § 146.82 cannot be met until 

after the well is drilled. For example, subparagraph (l) references (j), 

formation testing. Clearly formation testing 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 

38
post 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 available 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 information to be submitted before operation 

of the well is authorized (at §146.82(c)). 

EPA believes that this revision 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 injection well classes, which could help avoid 

confusion about how to meet the permitting requirements 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 modifications and additions that 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/edits 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 project. 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 project. 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 that the proposed rule be amended as 

follows: 

§146.84 Area of review and corrective action. 

(a) The area of review is the region surrounding the geologic 

sequestration project that may be impacted by the injection activity. 

The area of review is based on computational modeling that, TO THE 

39
EXTENT PRACTICABLE AND TO THE EXTENT DETERMINED TO BE NECESSARY BY 

THE 

DIRECTOR, accounts for the MATERIAL physical 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 regulation and the associated background document 

"Computational Modeling of Underground Injection of Carbon Dioxide for Determination of 

Area-of-Review and Potential Risk to Underground Sources of Drinking Water" (cited in the 

proposed rule preamble as USEPA, 2008d), substantiates the modeling requirements in the GS 

regulation and indicates that technology has advanced to the point that a CO2 injection project 

can be adequately modeled to support both prediction 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 science 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 the 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 physical and chemical properties of all phases of 

the injected CO2 stream and is based on available site characterization, 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 dioxide stream, and formation fluids. 

Under the proposed rule, the Director is required to determine and specify 

casing and cementing requirements to ensure that a proposed Class VI well is 

constructed and completed to prevent the movement of fluids into or between 

USDWs or into any unauthorized zones and to permit appropriate testing and 

monitoring. The proposed rule does not adequately explain or justify the 

information requirements set forth therein. 

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 fluids and of sufficient quality and quantity to maintain integrity 

over the design life the GS project. Both field and laboratory studies have found acid alteration 

where traditional well cements have been used for CO2 injection. Although the laboratory and 

field studies suggest that corrosion problems may not be severe, such problems cannot be 

conclusively ruled out, and the amount of available data on this problem is still relatively small. 

Laboratory investigation of cement degradation is an ongoing research area, and field-based 

40
studies are very few. There also does not appear to be a clear consensus at this time on the 

corrosion risks for the steel components of injection wells. Given the anticipated long lifespan of 

a Class VI well and the difficulties that would be associated with a corrosion-related well failure, 

EPA believes that the construction requirements at §146.86 are justified. 

EPA clarifies that the requirement at §146.86(b)(5) is that cement and cement additives must be 

compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to 

maintain integrity over the design life of the GS project. 

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

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

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 Cementing of Class VI Wells.(1) 

(v) Corrosiveness of the carbon dioxide stream, and formation fluids; 

The proposed rule requires an applicant to submit to the Director information on 

the corrosiveness of the carbon dioxide stream, and formation fluids. Neither 

the proposed rule nor the Preamble adequately explains whether the information 

requested is corrosiveness of the combined streams of CO2 and formation fluids, 

or each independent stream (which seems unnecessary). Further, the proposed rule 

or the Preamble should elaborate on what type of data may be acceptable - 

laboratory data for hypothetical streams, empirical testing, analogous wells? 

Clarification is requested on the aforementioned requirements. 

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 described in a number of technical ways. Corrosiveness 

should be described by the interaction between the CO2-modified fluid specific to the project 

and the well component (e.g., the cement, casing, tubing or packer) that could be affected. 

EPA adds that, with the permit application, the owner or operator must submit proposed well 

construction procedures, as specified at §146.82(a)(12)), that address the specific drilling and 

injection environment and the chemical and physical nature of the CO2 injected stream. The 

Director will evaluate the appropriateness of the proposed construction based on site-specific 

information about the injection project, as specified at §146.86(b)(1). In making this 

determination, the Director will also have the large array of geologic, geochemical, and 

hydrologic data on the site that the owner or operator must submit to meet the permit application 

requirements at §146.82(a). EPA adds that during the permit application process, the owner or 

operator and the permitting authority should work together to determine the specific tests that are 

41
appropriate, based on the site-specific circumstances. 

Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance 

will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

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 Cementing of Class VI Wells. (3) 

At least one long string casing, using a sufficient number of 

centralizers, must extend to the injection zone and must be cemented by 

circulating cement to the surface in one or more stages. 

* 

* 

* 

(5) Cement and cement additives must be compatible with the carbon 

dioxide stream and formation fluids and of sufficient quality and 

quantity to maintain integrity over the design life of the geologic 

sequestration project. The integrity and location of the cement shall be 

verified using technology capable of evaluating cement quality radially 

and identifying the location of channels to ensure that USDWs are not 

endangered. 

Additional proposed requirements affecting casing and cementing of Class VI 

wells are set forth in §§ 146.86 (b)(3) and (5) as quoted above. The requirement 

to cement the casing to the surface is unnecessary, expensive and contrary to 

best practices. Under acceptable best practices, the long string casing would 

not be cemented to the surface so that the pressure between the surface casing 

and long string can be monitored to determine if there is migration between the 

long-string casing and the surface casing. The cementing requirement proposed 

above would limit the ability to monitor for migration of injected fluids, in 

this case CO2, behind the casing. Additionally, Denbury’s field data indicates 

that the proposed casing and cementing requirements are costly while providing 

limited, if any benefit. According to our findings, under existing Class II UIC 

rules, a conventional cementing program costs approximately $20,000 per well. 

Under the cementing program proposed for Class VI wells the cost could escalate 

to approximately $193,000 per well-a potential $173,000 increase, representing a 

10% increase in total per well costs.[FN43] 

Denbury suggests an alternative that protects USDWs, but at a reasonable cost. 

Rather than require cementing of the long string casing to the surface, the 

proposed rule should require cement and cement additives to be compatible with 

the carbon dioxide stream and formation fluids that cover the injection zone and 

the confining zone, and then require standard (API, ASTM International, or 

42
comparable standards) industry cements to a certain distance above the confining 

zone. This would place cements that may require special additives at the point 

where USDWs are most effectively protected from the mixture of carbon dioxide 

and formation fluids that could produce carbonic acid. 

[43] For a typical well completed 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 supporting the GS Rule includes cementing costs of $1.20 per foot lengthinch diameter plus 25% of total cementing costs for use of corrosion-resistant cement. For a 

representative deep saline injection well used in the cost analysis, this translates to a total 

cementing cost of $406,500 per injection well, representing an incremental cost of approximately 

305,000 over baseline costs. This unit cost is in line with estimates provided by the commenter 

(actual costs are driven by well-specific characteristics). While the rule requirements necessitate 

these additional costs, the requirements are guided by the necessity to address the unique 

challenges posed by CO2 injection (including large injection volumes, the relative buoyancy of 

CO2, its corrosivity in the presence of water, the potential presence of impurities in captured 

CO2, and its mobility within subsurface geologic formations) as they protect USDWs from 

endangerment. 

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

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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 Class VI Wells. (3) At least one 

long string casing, using a sufficient number of centralizers, must 

extend to the injection zone and must be cemented by circulating cement 

to the surface INJECTION ZONE AND CONFINING ZONE AND AN 

AUTHORIZED DISTANCE ABOVE THE CONFINING ZONE, SUBMITTED BY THE 

PERMITTEE 

AND APPROVED BY THE DIRECTOR in one or more stages. 

* 

* 

* 

(5) TO PROTECT USDWS, Ccement and cement additives must be 

compatible with the carbon dioxide stream and formation fluids and of 

sufficient quality and quantity to maintain integrity over the 

43
design OPERATING life of the WELL geologic sequestration 

project MUST BE USED ACROSS THE INJECTION ZONE AND CONFINING ZONE. 

The integrity and location of the cement shall be verified using 

technology capable of evaluating cement quality radially and identifying 

the location of channels to ensure that USDWs are not endangered. 

Individual Response: EPA disagrees that the casing, cement, or other materials should only be 

designed for the period of the injection process, rather than the life of the sequestration project. 

GS projects are anticipated to have long life-spans in comparison to other types of deep injection 

wells. Not only must Class VI wells be able to function safely and properly over the lifespan of 

the GS project, but they must be constructed such that USDWs remain protected after well 

plugging. The requirements at §146.86 will ensure that the well can maintain integrity 

throughout the proposed life span of the project, including after the injection well is plugged and 

through the post-injection site care period and beyond. While the risk profile of a GS site will 

decrease following cessation of injection, EPA believes that Class VI wells must be designed to 

protect USDWs from endangerment for the life of the project. Furthermore, rigorous casing and 

cementing help ensure that the Class VI well will not serve as a conduit for movement of fluids 

associated with future injection operations. 

Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance 

will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

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 information a permittee must collect 

during the drilling and construction of a Class VI well, prior to actual 

injection activities. Although the proposed rule generally allows the Director 

to approve alternative methods that provide equivalent or better information, it 

is not clear that the Director can utilize that regulatory flexibility to waive 

unnecessary, duplicative testing which the proposed rule requires in several 

subparagraphs. 

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 information about the injection and 

confining zones and ensure that the well is being drilled and cased as approved, and has 

mechanical integrity. This information is needed to demonstrate that the well can be operated 

and tested in a manner that protects USDWs from endangerment. While the tests do provide 

information on some of the same items, each test provides unique pieces of information that 

build on each other and allow for interpretations not possible with a single test. Existing 

lithologic and geologic information may lack the details needed for site-specific well design and 

the geology needed to support protection of USDWs from endangerment. 

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

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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 installation of the 

surface casing:... 

(ii) A cement bond and variable density log, and a temperature log after 

the casing is set and cemented. 

The requirements in §146.87(a)(2)(ii) to secure and submit specified logs 

before, upon and after surface casing installation is excessive. The proposed 

rule fails to provide a sufficient justification for requiring a cement bond and 

variable density log before and upon installation of the long string casing, and 

requiring a temperature log after the casing is set and cemented. Temperature 

logs are seldom used in the drilling industry to determine cement 

characteristics as they do not provide useful data regarding the bonding of 

cement. The rules should be modified to allow the permittee to select between 

the specified logs and any other logging tool approved by the Director as 

follows: 

§146.87(a)(2)(ii) A cement bond and variable density log OR OTHER 

APPROVED TOOL, and OR a temperature log after the casing is set 

and cemented. [see § 146.12(d)(2)(i)(B) Criteria and Standards 

applicable to Class I nonhazardous wells: Construction Requirements.] 

* 

* 

* 

(5) Any alternative methods that provide equivalent or better 

information and that are required of and/or approved of by the Director. 

THE DIRECTOR MAY WAIVE ANY LOG OR TEST SPECIFIED IN THIS 

SUBPARAGRAPH. 

Individual Response: Cement bond, variable density, and temperature logs are required by 

§146.87(a)(2) upon installation of the surface casing. EPA disagrees that the surface casing 

logging requirements are excessive. Evaluation of all logs, surveys, and tests listed in the rule 

will provide detailed information on the parts of the well that will penetrate the lowermost 

USDW and provide information on the quality of the cement seal with surrounding formations in 

order to ensure protection of USDWs from endangerment. 

As described above, EPA disagrees that any tests should be waived. While the tests do provide 

information on some of the same items, the tests provide unique pieces of information which 

enhance each other and allow for interpretations not possible with a single test. For example, a 

variable density log can detect microannuli, fractures, and formation effects. Temperature logs 

can detect fluid or gas flow through channels that cannot be detected by either of the other tests. 

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

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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 geology before the casing is installed; 

and 

Once again, the proposed rule requires testing that would be of little benefit 

in protecting USDWs, but would impose significant costs on operators. For 

example, Denbury sees no basis to run a fracture finder log in every well. 

Fracture finder logs will only see minor fractures within the individual 

formations. The log does not provide information on whether these minor 

fractures can act as conduits between the injection zone and confining zone. To 

avoid unnecessary data collection and submittal, the rules should allow the 

applicant to propose and justify a logging suite based on the reservoir and 

geology associated with the particular CO2 project. The Director of course 

should be allowed to approve, or recommend revisions to the proposed suite. This 

would avoid mandating unneeded testing. Denbury suggests the following revised 

rule, incorporating this proposed change: 

§146.87 (a)( (3) Before and upon installation of the long string casing: 

(i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, 

fracture finder logs, and any other OR ANY SUITE OF LOGS 

SUBMITTED BY THE PERMITTEE 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 tests listed at §146.87(a) are necessary to verify 

information about the injection and confining zones and ensure that the well is being drilled and 

cased as approved and has mechanical integrity. 

EPA notes that owners or operators will describe in their permit applications how they will 

construct and test the well, and will also submit site-specific information about the subsurface 

geology. The Director will evaluate the proposed logging activities along with site-specific 

geologic information to identify geologic data of interest. 

EPA adds that, should alternative methods be shown to provide equivalent or better information 

or if site-specific conditions and risk factors dictate that other logs are necessary, the Director has 

the discretion at §146.87(a)(5) to require further logs and tests if necessary and to approve 

alternative methods that provide equivalent or better information. 

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

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

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

Comment: The proposed rule also requires unnecessary and duplicative logging with respect 

to the long-string casing. 

3. EPA Proposed §146.87(a)( (3) Before and upon installation of the long 

string casing: (ii) A cement bond and variable density log, and a 

temperature log after the casing is set and cemented. 

Denbury suggests that the logging options it recommends with respect to surface casing 

also apply for the long-string casing. Thus, the proposed rule should be revised as 

follows: 

§146.87(a)(3)(ii) A cement bond and variable density log OR OTHER 

APPROVED TOOL, and OR a temperature log after the casing is set 

and cemented. [see § 146.12(d)(2)(ii)(C) Criteria and Standards 

applicable to Class I nonhazardous wells: Construction Requirements.] 

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 information which enhance each other and allow for 

interpretations not possible with a single test. For example, a variable density log can detect 

microannuli, fractures, and formation effects. Temperature logs can detect fluid or gas flow 

through channels that cannot be detected by either of the other tests. 

Determining the quality of the cementing of the long-string casing is essential to the protection 

of USDWs from endangerment. EPA adds that, should alternative methods be shown to provide 

equivalent or better information, the Director may allow such alternatives under §146.87(a)(5). 

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

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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 samples from the injection zone(s). 

The Director may accept cores from nearby wells if the owner or operator 

can demonstrate that core retrieval is not possible and that such cores 

are representative of conditions at the well. The Director may require 

the owner or operator to core other formations in the borehole. 

47
Denbury opposes the requirement to collect cores from more than one (1) well 

within a CO2 project. As a practical matter, the majority of the important 

physical and geophysical properties of the injection reservoir, including the 

particular attributes of the confining formations can and are required to be 

evaluated from logs and other scientific, reliable measures. A "whole core," as 

specified in §146.87(b) is only a very small sample of the attributes of a 

reservoir and a sidewall core, an even smaller sample. The former is very 

expensive to collect, and the latter often not available. Neither is essential 

given the vast amount of data otherwise required, and multiple samples, as 

proposed by the rule, are not reasonable. The unreasonableness of the whole 

core, sidewall core and extra core sampling is evident upon consideration of the 

sheer volume of physical evidence that this provision alone may produce. For 

example, in Texas there are over 5000 existing Class II CO2 injection wells. If 

a small fraction of these wells are converted to Class VI CO2 injection wells 

following the completion of production activities, there will be a large 

universe of cuttings. Where will the regulatory agency store this magnitude of 

cuttings? This may become a particular problem given the total number of CO2 

sequestration projects that may be proposed. 

Denbury suggests the following: 

§146.87(b) AT THE SPECIFIC REQUEST OF THE DIRECTOR AND ONLY WHERE CORE 

RETRIEVAL IS POSSIBLE, TThe owner or operator must take and 

submit to the Director A whole cores or sidewall cores of the injection 

zone and confining system and formation fluid samples from the injection 

zone(s). The Director may accept cores from nearby wells if the owner 

or operator can demonstrate that core retrieval is not possible and that 

such cores are representative of conditions at the well. The Director 

may require the owner or operator to core other formations in the 

borehole. 

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 representative of conditions at the Class VI well. EPA 

clarifies that, at a minimum, reports on cores of injection zones, confining zones, and samples of 

formation fluids must be submitted. Section 146.87(b) gives the Director authority to require the 

owner or operator to core other formations in the borehole if necessary to provide sufficient 

geologic information to verify that the site is suitable for GS. 

EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In 

the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The 

owner or operator must take whole cores or sidewall cores of the injection zone and confining 

system and formation fluid samples from the injection zone(s), and must submit to the Director a 

detailed report prepared by a log analyst that includes: well log analyses (including well logs), 

core analyses, and formation fluid sample information...." 

48
Letter 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 following information concerning the 

injection and confining zone(s): 

(1) Fracture pressure; 

(2) Other physical and chemical characteristics of the injection and 

confining zones; and 

(3) Physical and chemical characteristics of the formation fluids in the 

injection zone. 

Subparagraph (d) of §146.87 provides permittees with a generic list of data that 

is required regarding the injection and confining zone. Fracture pressure is 

specified. Under the circumstances, fracture pressure should only be calculated, 

rather than "determined" as any determination based on techniques beyond 

mathematical calculation will require coring or perforation of the casing, 

potentially decreasing the mechanical integrity of the well and running directly 

counter to the objective of the proposed rules. With respect to other generic 

data EPA seeks regarding the injection and confining zones, the proposed rule 

does not to provide sufficient guidance to the permittee on the scope of data 

required on the formation fluids and reservoir zones. Denbury requests 

clarification and specifics both with respect to the nature and type of 

"physical and chemical characteristics" EPA expects a permittee to submit in 

response to the requirements of 146.87(d) (2) & (3). 

Individual Response: EPA disagrees that the wording at §146.87(d) would lead the owner or 

operator to employ destructive testing methods for determination of fracture pressure. The 

wording "determined or calculated" allows for calculations to be performed based on nondestructive methods. EPA is developing guidance on monitoring and testing that will describe 

recommended tests and procedures to assist owners/operators and Directors in evaluating the 

requirements for pre-operational logging and testing under §146.87, including providing 

information on the physical and chemical characteristics of the injection and confining zones. 

This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

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

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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 witness all logging and testing by this 

subpart. The owner or operator must submit a schedule of such activities 

to the Director 30 days prior to conducting the first test and submit 

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

The agency requires the submission of a proposed logging and testing schedule at 

least 30 days in advance of those proposed activities. Although a logging and 

testing schedule certainly can be designed 30 or more days in advance, the 

actual date that logging is performed is usually available only 24 to 48 hours 

in advance of actual logging operations. A mandatory 30 day notice is simply not 

practical for logging and testing. Denbury asks that notice requirements in this 

subpart be adjusted to take into account the practical limitations experienced 

routinely in field operations. Suggested revised language is set forth below. 

§146.87(f) The owner or operator must provide the Director with the 

opportunity to witness all logging and testing by this subpart. The 

owner or operator must submit a PROPOSED schedule of such activities to 

the Director AT LEAST 30 days prior to conducting the first test and 

submit NOTICE AT LEAST 24 HOURS IN ADVANCE OF THE CONDUCT OF ANY 

ACTUAL 

LOGGING AND TESTING. any changes to the schedule 30 days prior to the 

next scheduled test. 

Individual Response: EPA disagrees that the 30-day notification requirement is unreasonable. 

Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the 

permitting authority in each project will provide much needed field data for assurance of USDW 

protection from endangerment and will help update and refine the permitting process. Adequate 

timing of notification will ensure the Director's ability to be involved. 

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

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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 operating injection pressure, unless 

the Director determines that such requirement might harm the integrity 

of the well. 

EPA’s suggested Mechanical Integrity ("MI") rule to maintain pressure on the 

annulus exceeding the operating injection pressure will, in most cases, result 

in an exceedance of the burst pressure of the casing. 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 

50
EPA appears to recognize this likelihood and thus allows the Director to waive 

the requirement. However, the rule should 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 revision is encapsulated below: 

(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. IF THE DIRECTOR DETERMINES THAT SUCH REQUIREMENT WILL NOT 

HARM 

THE INTEGRITY OF THE WELL, Tthe owner or operator must maintain A 

POSITIVE PRESSURE on the annulus a pressure that exceeds the 

operating injection pressure. ., unless 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 geomechanical properties of the site based on information collected 

under §146.82 and meets the construction requirements at §146.86 would be able to maintain 

integrity if the annulus pressure were reasonably higher than injection pressure. 

The purpose of continuous pressure monitoring (to demonstrate internal MI) is to demonstrate 

that no pressure changes are occurring, because a drop in pressure on the 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 pressure, can indicate a 

leak. 

The GS rule, at §146.88(c), allows the Director to make exceptions if the Director determines 

that such a requirement might harm the integrity of the well. The final regulation at §146.88(c) 

requires that the owner or operator must maintain on the annulus a pressure that exceeds the 

operating injection pressure, unless the Director determines that such requirement might harm 

the integrity of the well 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 monitor: 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 install 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 

51
permitted 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 unnecessary 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 fluids from exiting the wellbore. They 

are used in off-shore operations because of the risk of damage to the wellhead 

from atmospheric or anthropogenic phenomenon, such as a hurricane causing 

extensive platform damage or a ship colliding with a platform. But in an onshore 

injection system, a down-hole shut-off system 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 limited to off-shore operations. 

Individual Response: After evaluating the risks and benefits of down-hole shut-off systems and 

considering additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells since 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 owners 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 automatic surface shut-off 

devices for onshore wells (and affording Director's discretion to require down-hole devices 

where necessary) ensures that proper precautions are taken to prevent subsurface fluid movement 

and ensure protection of USDWs. 

The GS rule, at §146.88(e)(3), requires 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 construction and operational conditions for offshore Class 

VI wells, including isolation from shorelines and the need to construct 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 facilities is lower than that 

for off-shore facilities, down-hole shut-off valves are still commonly used in onshore facilities 

such as acid gas injection wells and high pressure, high-temperature wells. While valve failure is 

a concern, EPA believes that technology has advanced sufficiently to make valve failure a rare 

occurrence and to appropriately handle such failure if it occurs. For example, wireline retrievable 

devices can allow repair or replacement of damaged devices without necessitating pulling the 

tubing. 

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

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4520 2.5.1 Continuous internal mechanical integrity monitoring (seeking 

comment) 

Comment: Furthermore, the requirement to continuously monitor the annulus fluid volume is 

impractical, because it does not provide any 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. Denbury recommends the following: 

§146.88(e) The owner or operator must install and use continuous 

recording devices to monitor: 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 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 operator 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 intact 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 supercritical nature of the injectate, the potential 

geomechanical stresses in the wellbore, and the potential for movement of the buoyant CO2 in 

the event of a MI loss make it an important safety consideration for GS projects. Continuous 

pressure monitoring allows immediate identification of corrosion-related well integrity loss. EPA 

agrees with the commenter that recording annulus 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 also believes that knowing the annulus fluid volume 

added is sufficient to meet the intent of the requirement. The final GS rule requires that owners 

or operators use continuous recording devices to monitor injection pressure, rate, and volume, as 

well as the pressure on the annulus between the tubing and the long string casing. It also 

modifies the requirement in the proposed rule to continuously monitor annulus fluid volume; it 

now requires recording of annulus fluid 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/edits 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 

53
OPERATOR 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 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; 

(f) If aN down-hole automatic shutdown is triggered or a loss of 

mechanical integrity is discovered, 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 benefits of down-hole shut-off systems and 

considering additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells since 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 owners 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), requires 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 construction and operational conditions for offshore Class 

VI wells, including isolation from shorelines and the need to construct 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 installation of automatic surface shut-off devices for onshore 

wells (and affording Director's discretion to require down-hole devices where necessary) and 

automatic down-hole shut-off devices for offshore wells in submerged lands within the 

jurisdiction of a State ensures that proper precautions 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/edits 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 paragraph (a)(2) of this section: 

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

Among the test protocols prescribed by the 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 Director. Conducting a casing inspection log 

will require the tubing to be pulled from a well, and that in turn substantially 

increases the possibility of 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 the following 

edit: 

§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 paragraph (a)(2) of this section: 

(3) A casing inspection log, if A TRACER 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-string casing, and is required if the Director 

determines that it is necessary based on site-specific information. EPA has revised the final GS 

rule to require that the frequency of the casing inspection 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/edits 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) Installation and use, except during well 

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 above, 

Denbury is unaware of a methodology to monitor 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 sufficient to meet the intent of continuous 

55
monitoring of the pressure on the annulus. The final GS rule at §146.90 (b) requires that owners 

or operators use 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 added. 

Letter ID: 0215 Comment ID: 24309 Letter Lines: 1401 to 1435 ; 1923 to 1934 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: 2. EPA Proposed §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 meet the minimum standards for material strength and 

performance set forth in § 146.86(b) by: 

(1) Placing coupons of the well construction 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 method 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 and 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 course alternatives approved by the Director) will not 

provide meaningful information regarding the mechanical integrity 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 SATURATED 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 construction 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 method approved by the Director. THE REQUIREMENTS 

OF THIS SUBPART ARE WAIVED WHEN THE CARBON DIOXIDE STREAM IS 

DEHYDRATED 

56
TO MEET PIPELINE SPECIFICATIONS. 

[44] For evidence on CO2 corrosiveness in the absence of free water see Don 

Duttlinger, "Enhanced Recovery Intertwines Naturally With CO2 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, CO2 is noncorrosive as long as it is dry. 

Proving that point, Kinder Morgan has hydro-tested the 32-year-old CRC Pipeline 

built in 1971 to transport CO2. 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 Reef 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 monitoring 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 considered. EPA believes that the testing methods specified in the 

rule are appropriate and have been used successfully by Class I hazardous waste injection well 

owners or operators. 

Several laboratory studies and a limited number of field studies have investigated and 

characterized the effects of carbonic acid on well materials. Laboratory studies (e.g., Kutchko et 

al., 2007; Kutchko et al., 2008) consistently identify alterations (typically carbonation) of cement 

as the result of interactions between cement and CO2-saturated brine. 

Currently, there are only a few analyses of cement from wells that have been in prolonged 

contact with CO2 in actual field (down-hole) conditions. Evaluation of cement from a well at the 

Scurry Area Canyon Reef Operators Committee (SACROC) site showed alteration, but did not 

show degradation that compromised the structural integrity of the 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 addresses the effects of corrosion of steel tubing and pipes. Lopez et 

al. (2003) noted that 60 percent of oilfield failures are related to the effects of carbonic acid from 

produced brines on carbon and low alloy steels. 

Laboratory investigation of cement alteration/degradation is an ongoing research area. Few fieldbased studies have been completed to date. The laboratory and field studies currently available 

suggest that corrosion problems can be managed; however, there is not a large enough body of 

research to rule out potential corrosion problems of steel components of injection wells. The 

IPCC (2005) report on carbon dioxide capture and storage reviewed oil and gas industry 

57
experience with gas injection wells, close industry analogues to CO2 injection wells. The report 

stated that while the design of CO2 injection wells will be very similar to gas injection wells, 

most down-hole components of the CO2 injection wells will “need to be upgraded for higher 

pressure ratings and corrosion resistance.” Given 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 that corrosion monitoring in the down-hole 

environment is justified. For these reasons, the final rule requires quarterly corrosion monitoring 

(at §146.90(c)). See the final rule and preamble for 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 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 the actual data, or merely an analysis of the pressure 

fall-off test? 

Individual Response: EPA expects that the Director would 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 additional monitoring, as required by the 

Director, necessary to support, upgrade, and improve computational 

modeling of the area of review evaluation 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 Director undefined 

discretion to order unlimited and unspecified 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 

58
through appropriate rulemaking procedures and based on an adequate factual and 

scientific record. However, adopting an open-ended power to require "any" 

additional monitoring, at this early stage, 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 costs, creating a barrier to capital 

formation and discouraging geologic sequestration. Accordingly, Denbury 

recommends deleting this section. 

Individual Response: EPA does not believe that UIC Directors should have undefined 

discretion when ordering additional monitoring 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 additional testing and monitoring requirements are 

required to ensure the protection of USDWs. 

EPA is developing guidance on testing and monitoring to assist owners or operators and 

Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface 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/edits to rule language 

Comment Code: 5100 2.8.1 Injection well plugging activities (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 wellbore to be flushed prior to plugging 

and thus it is unnecessary to use cement "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 type and grade and quantity of 

material to be used in plugging. The material must be compatible with 

the carbon dioxide stream; 

59
Individual Response: EPA believes, considering the potentially 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 retains 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/edits 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 post-injection site 

care. There is, however, no factual or scientific basis for such an extensive 

period. Under EPA’s Resource Conservation and Recovery Act rules, which regulate 

the disposal of hazardous wastes, post closure care is limited to 30 

years.[FN45] Defaulting to an excessively long period will increase costs and 

introduce greater regulatory uncertainty, which will discourage capital 

formation around CO2 sequestration. A more prudent 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 circumstances warrant a longer post-injection 

site care period. 

Additionally, the proposed rule’s 50 year default post 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 incentive 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 site care rules be reconfigured to 

require a more limited mandatory post-injection site care timeframe, and to 

allow for closure at the end of that period unless the Director affirmatively 

acts to extend the post-injection site care period. 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 

comply with a plan for post-injection 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 application to be 

60
approved 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 site closure as demonstrated in 

the area of review evaluation required under § 146.84(b); 

(iii) A description of post-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, owners or operators of Class VI 

wells must either submit an amended post-injection site care and site 

closure plan or demonstrate to the Director through monitoring data and 

modeling results that no amendment to the plan is needed. 

(4) The owner or operator may modify 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 monitor 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 continue 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 sequestration 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 geologic sequestration project no longer 

poses an endangerment to USDWs, the Director may approve an amendment to 

the post injection site care and site closure plan to reduce the 

frequency of monitoring or may authorize 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 closure, the owner or 

operator must submit to the Director a demonstration, based on 

monitoring and other site specific data, that the carbon dioxide plume 

and pressure front have stabilized and that no additional monitoring is 

needed to assure that the geologic sequestration project does not pose 

an endangerment to USDWs. 

61
(4) IF WITHIN 180 DAYS AFTER THE SUBMITTAL OF THE DATA 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 OPERATOR OF HIS DETERMINATION AND THE 

BASIS 

THEREFORE, AND If such a demonstration 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 SUBMITTAL OF THE DATA REQUIRED 

UNDER SUBPARAGRAPH (3) ABOVE THE DIRECTOR FAILS 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 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 any changes have been made to the 

original post-injection site care and site closure plan, the owner or 

operator must also provide the revised 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 operator 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 operator must submit a site closure 

report within 90 days that must thereafter be retained at a location 

designated by the Director. The report must include: 

(1) Documentation of appropriate injection and monitoring 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 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 Administrator of the appropriate EPA 

Regional Office; 

(2) Documentation of appropriate notification and information to 

such State, local and tribal authorities as have authority over drilling 

activities to enable such State and local authorities to impose 

appropriate conditions on subsequent drilling activities that may 

penetrate the injection and confining zone(s); and 

(3) Records reflecting the nature, composition and volume of the 

62
carbon dioxide stream. 

(f) Each owner or operator of a Class 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 perpetuity provide 

any potential purchaser of the property the following information: 

(1) The fact that land has been used to sequester carbon dioxide; 

(2) The name of the State agency, local authority, and/or tribe 

with which the survey plat was filed, 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 the post-injection site care period. 

The owner or operator must deliver the 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 requirements in the final GS rule, §146.93(b), 

incorporate a combination of a 50-year default post-injection site care timeframe, 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-injection period based on site-specific 

data, pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a 

Class VI well owner or operator to demonstrate, during the permitting process based on 

substantial data, that an alternative PISC timeframe may be appropriate if it ensures nonendangerment of USDWs pursuant to requirements at §146.93(c). 

EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in all but a limited number of cases. This default 50 

year post-injection site care timeframe represents a reasonable and protective monitoring period 

based on a review of research studies, industry reports, and existing environmental programs, 

and evaluation of public comments. 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. EPA expects that the Director will consider the types of information the commenter 

describes in determining whether the plume and pressure front no longer pose a risk of 

63
64

endangerment to USDWs and post-injection site 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 proposed well plugging plans and post-injection site 

care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells, perform 

post-injection monitoring, demonstrate the appropriateness of an alternative post-injection site 

care time frame, demonstrate non-endangerment, and perform site closure activities. The 

guidance will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.