1.4 – 1.5 –  Responses to Public Comments on Scientific Background and the Need for

a New Class of Well

This file contains responses to public comments on the scientific background of GS and

the need for a new class of UIC injection well (comment codes 1800 to 2066).  This

section includes comments on research on GS, technical workshops on the rule, and

EPA’s technical guidance for pilot GS projects. It also includes comments on the

appropriateness of using existing Class I, II, or V requirements for GS and the

grandfathering of existing wells.

The table below presents all of the EPA‐assigned comment codes that are included in

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

move among the comment codes.   

Topics included in this summary and associated comment codes

Topic Code

1.4 Scientific Background/Informing the Proposal 1800

1.4.1 Research on identifying risks to USDWs 1810

1.4.1.1 Vulnerability Evaluation Framework (VEF) 1820

1.4.1.2 Lawrence Berkeley National Laboratory (LBNL) research (No comments were

submitted for this topic.)

1830

1.4.1.3 Other research 1840

1.4.2 CO2 GS Field Research   1850

1.4.2.1 DOE Regional Carbon Sequestration Partnerships 1852

1.4.2.2 Other Pilot Projects 1854

1.4.2.3 Other U.S. Research (Princeton University, MIT) (No comments were submitted for

this topic.)

1856

1.4.2.4 International GS efforts 1858

1.4.3 Technical workshops 1900

1.4.4 Stakeholder outreach 1910

1.4.4.1 Public stakeholder meetings (No comments were submitted for this topic.) 1920

1.4.4.2 Consultations with State, Tribal, and local Associations (e.g., GWPC, IOGCC) 1930

1.4.4.3 Consultations with Industry; experience with other wells 1940

1.4.4.4 Consultations with electric and water utilities (No comments were submitted for this

topic.)

1950

1.4.4.5 Consultations with NGOs, e.g., environmental and citizens groups 1960

1.4.4.6 Need for other consultations 1970

1.4.5 EPA's Technical Guidance for Pilot GS Projects (No comments were submitted for this

topic.)

1980

1.5 Need for a New Class of Injection Well 2000

1.5.1 Support Class VI designation 2020

1.5.2 Oppose Class VI designation 2040

1.5.2.1 Oppose Class VI/ Support Class I (No comments were submitted for this topic.) 2042

1.5.2.2 Oppose Class VI/ Support Class II 2044

1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ dividing line between

Class II and VI  

2046

1.5.2.4 Oppose Class VI/ Support Class V experimental technology well 2048
1.5.3 Comments on grandfathering of existing wells   2060

1.5.3.1 Grandfathering construction of Class I wells   2062

1.5.3.2 Grandfathering construction of Class II wells   2064

1.5.3.3 Grandfathering construction of Class V wells   2066

Every comment on these topic areas and the associated response is included in this

summary; there is some repetition where multiple commenters made the same

comment.

Responses to letters from individual commenters or organizations are also available in

the rulemaking docket.

  
Comment Code: 1800 1.4 Scientific Background/Informing the Proposal 

Individual Comments

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23371

Comment: The need for better data for GS to work -- Pg. 44 

In non-oil and gas states (or perhaps some mining states) there is little known 

about the subsurface geology. APPA believes that USGS and other agencies 

can help the EPA and state agency directors in better characterizing these 

formations. 

Response: While developing the GS regulation, EPA evaluated relevant GS research, including

projects conducted by the seven regional carbon sequestration partnerships funded by the U.S.

Department of Energy (DOE) and coordinated through the National Energy Technology Laboratory

(NETL), and several international projects. Additionally, EPA's Office of Water continues to fund

research at the Lawrence Berkeley National Laboratory examining the effects of CO2 interaction on

ground water aquifers and any potential mobilization of trace elements that may occur. EPA is

communicating with other research organizations and academic institutions including, among others,

Princeton University, Massachusetts Institute of Technology, and Montana State University, where

specific research on geologic sequestration, injection well materials, and CO2 monitoring techniques

is in progress. EPA is also working with DOE, USGS, and others to identify tools and training

techniques that will provide GS permitting assistance and technical expertise as appropriate.

Additionally, EPA's Office of Research and Development (ORD) is undertaking multiple research

efforts on GS. Topics of research include bolstering different default thermodynamic databases to

include more comprehensive information on aqueous complexes and solid-phases that contain

carbonate/bicarbonate and toxic elements for which EPA has a listed maximum contaminant level

(MCL) for safe drinking water. 

ORD's National Center for Environmental Research (NCER) awarded six Science To Achieve

Results (STAR) grants in the Fall of 2009 to recipients from major universities and institutions

within the scope of the "Integrated Design, Modeling and Monitoring of Geologic Sequestration of

Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water" research area. These

projects, which started in late 2009, include these lead institutions with specific topics of

investigation: Clemson University will study potential impacts to drinking water aquifers of CO2-

rich dissolved brines; the University of Illinois-Urbana will conduct research related to reducing

hydrologic and geochemical uncertainties associated with CO2 sequestration in deep, saline

reservoirs; the University of Texas at Austin will assess appropriate monitoring approaches at

geologic sequestration sites; the University of Utah will integrate design, monitoring, and modeling

of GS to assist in developing a practical methodology for characterizing risks to USDWs; Columbia

University will conduct laboratory experiments on shallow aquifer systems to improve understanding

of geochemical and microbiological reactions under low pH/high CO2 stress; and Princeton

University will develop a set of computational tools to model CO2 and brine movement associated

with GS.

In response to the comment regarding the amount of data available on the subsurface geology of

states that do not produce oil or gas, EPA clarifies that the permitting requirements at §146.82

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require an extensive evaluation of the geologic conditions at a proposed GS site to demonstrate the

suitability of a potential project site for GS. If adequate maps and cross sections do not exist to

support a thorough evaluation of the site, the owner or operator must produce the information (e.g.,

through additional, new studies) and the Director has the authority to request additional information.

See §146.82(a)(21).

EPA is using an adaptive approach to regulating GS under the UIC Program. Even after finalization

of the GS regulation, the Agency plans to collect and review 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.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23381

Comment: 9. State governments, the EPA, power plant owner/operators, water utilities and 

the public need more data on water and subsurface geology/hydrology before we 

can actually begin wide scale deployment of new CCS plants. APPA strongly 

encourages EPA, DOE/NETL, U.S. Geological Survey (USGS) and state 

geologists/hydrologists to work together to improve our knowledge on both 

surface and subsurface geology. APPA believes it will be helpful for Congress to 

better understand the technology and to fully fund demonstration projects so 

that there is sufficient understanding of geology to support widespread 

geosequestration. 

Response: As described in the previous response, EPA is tracking continuing research on CCS

conducted by other federal agencies. EPA clarifies that Congressional actions and budget issues are

outside the scope of the GS rulemaking.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23387

Other EPA Comment Codes and Descriptions: 1330 1.1.3.1 Support use of GS in general; 1610

1.3.1 Risks to USDWs 

Comment: Our comments here should not deny the viability of CCS in some subsurface 

locations nor be read as APPA’s view that geologic sequestration works in all 

geologic locations or for all power plants. There is a great deal that we do not 

yet know about the wide variety of geologic formations to know that there are no 

risks to USDWs or that we could identify specifically what those risks might be. 

APPA hopes that on-going private and public research in the United States, 

Canada, Australia, and Europe will affirm that there are no risks to drinking 

water supplies or that the risks are so truly negligible that there is no reason 

to hesitate to use this technology. But we cannot presume that there are no 

risks simply based upon the commercial and technical success in CO2 recycling in 

Class II injection locations that are managed as production fields. It has been 

presumed that because the CO2 injections began in the Permian Basin of West 

Texas in the late 1970s that the CO2 from those tertiary recovery fields (for 

oil or gas) is actually still in the formation. In most cases the CO2 was 

recycled and used in different production operations. Even if the CO2 was 

injected 25-35 years ago, the CO2 may not still reside or remain in storage 

there. Because we have not seen large storage fields where the CO2 was stored 

2
for 10-30 years on a sustained basis, there is not as much known about the 

geologic formations, the adequacy of holding capacity and subsurface impacts as 

we would like to know. Also, in many cases, those oil or gas production fields 

are regulated differently than a newly established long-term GS formation would 

be regulated if it were owned/operated by a power company. 

Response: EPA agrees with the commenter that the risks involved in GS projects are different than

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 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 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. Please also see the research described in

the above response.

As part of its adaptive rulemaking approach, the Agency plans, every six years, to collect and review

data on GS projects to determine whether the appropriate amount and types of information and

appropriate documentation are being collected, and to determine if modifications to the requirements

are appropriate or necessary.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23430

Comment: for injection and long-term storage of CO2. Nor do we know what the storage 

capacity is for those geologic formations given the volume of CO2 from power 

plants. We believe that DOE’s regional sequestration pilots, USGS, and other 

agencies can help the EPA and state agency directors in better characterizing 

these formations and ruling out transmissible faults, historically abandoned 

wells or mines, or poorly closed oil/gas operations from the 1930s where the 

well was closed with very poor closure mechanisms that would not prevent 

seepage. These formations that need to be considered by these agencies include 

deep saline formations, since we believe that most oil and gas formations will 

be saturated with CO2 in the first few years of broad commercial deployment. Oil 

and gas states have had motivation to keep up with subsurface mapping and 

preliminary characterization of the geology and hydrology because of the revenue 

streams from oil/gas sales and taxes back to the states. States will need to 

provide much clearer preliminary characterizations of the subsurface before this 

technology is commercially deployable because even the most modest subsurface 

characterization in a deep saline aquifer can take millions of dollars. Many 

power plant owner operators will hesitate to undertake such studies in non oil 

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and gas states. APPA encourages the state agencies to use the available training 

and resources from USGS. EPA and state agencies should also become familiar with 

and be trained to use the SEQURE program, licensed by the Department of Energy’s 

NETL program. SEQURE is an aerial methane detection program which can be used in 

each state to identify abandoned or orphaned oil and gas wells, mines, and 

perhaps other subsurface faults that could inadvertently lead to leakage and 

ultimate risks to USDWs. Other programs may be appropriate in addition to 

SEQURE. APPA does not intend to close the door to other modern ways to better 

characterize drinking water resources and the surrounding geology but we 

encourage the use of SEQURE. We defer to our colleagues at the American Water 

Works Association, the AWWA Research Foundation (AwwaRF), and the Association of 

Metropolitan Water Agencies who might offer other insights as to what else is 

needed. Further, APPA encourages state directors to communicate in substantives 

ways with the state hydrologist or geologist. Many states have not had any 

motivation to review subsurface geology in many decades. Updating maps and 

ruling out areas with faults or other unintended methods of conveyance for CO2 

migration will be essential to make this program work. APPA encourages the U.S. 

EPA and states to meet with USGS to discuss other tools available to the EPA and 

to states agencies. 

Response: As discussed previously, EPA continues to fund and track research on geology as it

relates to CCS. Information about this research is available on EPA's safewater website and ORD's

web site.

In response to the comment regarding the amount of data available on the subsurface geology of

states that do not produce oil or gas, EPA clarifies that the permitting requirements at §146.82

require an extensive evaluation of the geologic conditions at a proposed GS site to demonstrate the

suitability of a potential project site for GS. If adequate maps and cross sections do not exist to

support a thorough evaluation of the site, the owner or operator must produce the information (e.g.,

through additional, new studies), and the Director has the authority to request additional information

under §146.82(a)(21). EPA also agrees with the commenter that communication among

knowledgeable staff, such state hydrologists or geologists, is important to ensure that USDWs are

protected. EPA encourages such communication wherever appropriate or necessary so that the

Director will have all of the information needed to support permitting decisions. 

Regarding the use of SEQURE to identify abandoned wells, EPA notes that owners or operators may

propose to use whatever methods they choose to support the AoR and corrective action process

required at §146.84, as long as they are approved by the Director as part of the AoR and corrective

action plan. Please see EPA's AoR and corrective action guidance, available on EPA’s website at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm, for additional information.

Commenter Name: Ronald Evans Letter ID: 0215

Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24278

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 

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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.[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. 

5
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 

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 

6
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 

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 

7
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 

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 

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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. 

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 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.

Commenter Name: Ronald Evans Letter ID: 0215

9
Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24279

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 

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 

10
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 

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 

11
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. 

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.

Commenter Name: Jonathon Palm Letter ID: 0222

Commenter Organization: Nevada Division of Environmental Protection, Bureau

of Water Pollution Control

Comment ID:

21640

Other EPA Comment Codes and Descriptions: 1510 1.2.2.3 Need for additional study 

Comment: 1. Before a project can be approved, there must be an accurate determination of 

the integrity and capacity of the underground reservoir that is to receive the 

injected fluids. At this time, it does not appear that the required expertise 

and good science are available and will be used in the evaluation of the 

underground reservoir to verify that the formation is capable of long term 

12
storage. If the integrity is not realized, the Co2 and other gasses would escape 

and possibly re-enter the atmosphere. No benefit to the reduction of greenhouse 

gasses would be realized, or, worse, some unforeseen, negative consequence would 

result. Recall the MTBE issue where the remedy to an air pollution problem 

turned out to be a widespread and costly contamination of groundwater. 

Response: EPA clarifies that the permitting requirements at §146.82 require an extensive evaluation

of the geologic conditions at a proposed GS site to demonstrate the suitability of a potential project

site for GS. If adequate maps and cross sections do not exist to support a thorough evaluation of the

site, the owner or operator must produce the information (e.g., through additional, new studies), and

the Director has the authority to request additional information under §146.82(a)(21).

While developing the GS regulation, EPA evaluated relevant GS research, including projects

conducted by the seven regional carbon sequestration partnerships funded by the U.S. Department of

Energy (DOE) and coordinated through the National Energy Technology Laboratory (NETL), and

several international projects. Additionally, EPA's Office of Water continues to fund research at the

Lawrence Berkeley National Laboratory examining the effects of CO2 interaction on ground water

aquifers and any potential mobilization of trace elements that may occur. EPA is communicating

with other research organizations and academic institutions including, among others, Princeton

University, Massachusetts Institute of Technology, and Montana State University, where specific

research on geologic sequestration, injection well materials, and CO2 monitoring techniques is in

progress. EPA is also working with DOE, USGS, and others to identify tools and training techniques

that will provide GS permitting assistance and technical expertise as appropriate. Additionally, EPA's

Office of Research and Development (ORD) is undertaking multiple research efforts on GS. 

EPA disagrees that GS is analogous to the MTBE experience. EPA believes that large scale GS can

be done safely: the GS regulation builds upon the long-standing protective framework of the UIC

program, which has been regulating the injection of billions of gallons of fluids for decades. The GS

regulation enhances this framework with requirements for GS wells that are tailored to address the

unique issues associated with large-scale GS including large injection volumes, the relative buoyancy

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

CO2, and its mobility within subsurface geologic formations. These additional protective

requirements include more extensive geologic testing, detailed computational modeling of the AoR

and periodic re-evaluations, detailed requirements for monitoring and tracking the CO2 plume and

pressure front, and extended post-injection monitoring and site care.

Comment Code: 1810 1.4.1 Research on identifying risks to USDWs 

Individual Comments

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114

Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22531

Comment: EPA CAREFULLY SELECTS CITATIONS 

EPA (2008), at 73 FR 43515, col. 2, cites Burton et al. (2007) as supporting the 

availability and adequacy of "current monitoring technologies" for monitoring 

pressures in GS project (sic)." EPA does not cite the serious questions raised 

13
by Nicot and Hovarka (2008) at the EPA January 16, 2008 CO2 meeting in New 

Orleans, wherein Nicot and Hovarka (2008) presented a PowerPoint slide show 

regarding monitoring insitu problems. Hovarka (2008) reiterates serious concern 

discussed in 2007 regarding field monitoring capabilities of currently available 

tools. At 73 FR 43515, col. 3, EPA selects the Nimiz and Hudson (2005) report 

to justify insitu monitoring of CO2. EPA did not cite the Nicot and Hovarka 

(2007) presentation, which makes a point of expressing serious concern regarding 

insitu monitoring using current techniques. 

EPA cites Flett (2007), et al. at 73 FR 43519. The reader is directed to the 

EPA reference section (73 FR 43533) of the proposed rule preamble and to EPA 

(2008b). The reader finds a) no citation as to the origin of the reference at 

73 FR 43533 and b) EPA 2008b is a paper regarding "Vulnerability Evaluation 

Framework ...", which, in turn, refers the reader to the instant proposed rule. 

EPA consistently, excludes reference which do not support the EPA preconceived 

ideas! 

Burton, E., R. Myhre, L. Myer, and K. Birkinshaw. 2007. Geologic Carbon 

Sequestration Strategies for California. Report to the Legislature. November, 

2007. CEC-500-2007-100-SF. 

Flett, M., R. Gurton, and G. Weir. 2007. Heterogeneous Saline Formations for 

Carbon Dioxide Disposal: Impact of Varying Heterogeneity on Containment and 

Trapping. 73 FR 43491-43541. 

Hovarka, S., 2008. "Recent Progress and Big Ideas on Geologic Sequestering, 

US/International Perspective." 11 January. 

Nicot, J.P. and S.D. Hovorka. 2008. Role of Geochemical Monitoring in Geologic 

Sequestration. Presented at the CO2 Geologic Sequestration Technical Workshop on 

Measurement, Monitoring, and Verification, January 16,. New Orleans, LA. 

Response: EPA disagrees that the GS Rule is based on limited research. While developing the GS

rule, EPA conducted an extensive literature search. The papers cited in the preamble are those EPA

believes directly address the unique issues associated with CO2 GS, and provide overwhelming

evidence supporting the rule requirements, including testing and monitoring requirements. 

EPA also considered information from laboratory, modeling, and field research as it developed the

requirements for GS wells. In addition to laboratory studies and modeling research that provide

relevant information on GS, the Agency is also involved in collecting and analyzing GS project data

and permit information from a variety of sources. Most notably, EPA has evaluated permits and

reviewed operational data and information associated with the seven regional carbon sequestration

partnerships funded by the U.S. Department of Energy and coordinated through the National Energy

Technology Laboratory (NETL), and several international projects. In addition to the information

cited in the preamble to the proposed rule, EPA published a Notice of Data Availability and Request

for Comment (NODA) on August 31, 2009 (74 FR 44802), in which the Agency described the

preliminary 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 under the UIC Program. Even after finalization

14
of the GS regulation, 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.

Commenter Name: Robert Bessette Letter ID: 0139

Commenter Organization: Council of Industrial Boiler Owners (CIBO) Comment ID: 23080

Comment: in the proposal. Throughout the proposal EPA identifies significant areas 

needing basic research. Risks are not sufficiently defined and therefore not 

adequately quantified. Costs are outright unquantifiable, based in part on the 

unquantified risk. EPA notes that it intends to finalize a rule in 2010 or 

Response: EPA is working with DOE, national laboratories (such as Lawrence Berkeley National

Laboratories), the USGS, and internal Agency Offices (e.g., Office of Research and Development)

on research on various aspects of GS, including potential risks to USDWs. EPA published a Notice

of Data Availability and Request for Comment on August 31, 2009 (74 FR 44802), in which the

Agency described two studies by the Lawrence Berkeley National Laboratory on the potential effects

of CO2 injection on USDWs and human health in the event that a GS project is not properly sited,

operated, or managed. These studies are in the rulemaking docket and on LBNL's website at

http://esd.lbl.gov/GCS/projects/CO2/index_CO2.html. 

The Agency will continue to track GS project developments and evaluate new and ongoing research

and information to ensure USDW protection. EPA is using an adaptive approach to regulating GS

under the UIC Program. Even after finalization of the GS regulation, the Agency plans to collect and

review 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.

Commenter Name: James Taft Letter ID: 0172

Commenter Organization: Association of State Drinking Water Administrators

(ASDWA)

Comment ID:

23452

Comment: Research on Fluid Movement: 

EPA should promote and support research and data collection to determine the 

risk associated with geologic sequestration of carbon dioxide and to demonstrate 

that there is no fluid movement into a USDW. Some state laws regarding aquifer 

storage and recovery do not allow for any displacement of water. 

Response: EPA is working with DOE, national laboratories (such as Lawrence Berkeley National

Laboratories), USGS, and internal Agency Offices (e.g., Office of Research and Development) on

research on various aspects of GS, including potential risks to USDWs. EPA published a NODA and

Request for Comment on August 31, 2009 (74 FR 44802), in which the Agency described two

studies by the LBNL on the potential effects of CO2 injection on USDWs and human health in the

event that a GS project is not properly sited, operated, or managed. These studies are in the

rulemaking docket and on LBNL's website at http://esd.lbl.gov/GCS/projects/CO2/index_CO2.html. 

EPA is also funding a project at LBNL to integrate experimental and modeling efforts to evaluate the

potential consequences of CO2 leaks from GS operations into ground water resources. 

15
EPA is tracking other recent research on GS and USDW protection including the following studies

(which are available in the docket for the rulemaking):

• Smyth et al. (2008) reviewed modeling and laboratory experiments and field results from

groundwater studies conducted at SACROC, an ER site in west Texas where tens of millions of tons

of CO2 have been injected for over 30 years.

• Zheng et al. (2008) used more than 38,000 groundwater quality analyses from aquifers throughout

the US to perform reactive transport modeling of groundwater quality after the intrusion of CO2. The

model simulations indicate that aquifers containing more carbonate and clay minerals are less

vulnerable to CO2 intrusion, and that, while under certain conditions CO2 can potentially mobilize

metals present in the aquifer, mobilized amounts of the metals are always below health-based limits.

• Kharaka et al. (2009) conducted CO2 injection field tests in Montana and reported that shallowly

injected CO2 can affect the chemistry of shallow groundwater by decreasing pH and mobilizing rock

and soil ions. 

• Nicot (2008) modeled an injection roughly equivalent to 50 Mt CO2/year for 50 years in an area

that is hydrologically similar to the Gulf Coast Basin. Model results indicate an average water table

rise of approximately 1 meter with a minor increase in stream baseflow and a larger increase in

ground water evapotranspiration. 

ORD's National Center for Environmental Research (NCER) awarded six Science To Achieve

Results (STAR) grants in the Fall of 2009 to recipients from major universities and institutions

within the scope of the "Integrated Design, Modeling and Monitoring of Geologic Sequestration of

Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water" research area. These

projects, which started in late 2009, include these lead institutions with specific topics of

investigation: Clemson University will study potential impacts to drinking water aquifers of CO2-

rich dissolved brines; the University of Illinois-Urbana will conduct research related to reducing

hydrologic and geochemical uncertainties associated with CO2 sequestration in deep, saline

reservoirs; the University of Texas at Austin will assess appropriate monitoring approaches at

geologic sequestration sites; the University of Utah will integrate design, monitoring, and modeling

of GS to assist in developing a practical methodology for characterizing risks to USDWs; Columbia

University will conduct laboratory experiments on shallow aquifer systems to improve understanding

of geochemical and microbiological reactions under low pH/high CO2 stress; and Princeton

University will develop a set of computational tools to model CO2 and brine movement associated

with GS.

In response to the comment that some state aquifer storage laws do not allow for any water

displacement, EPA clarifies that the purpose of the Class VI requirements is to ensure the appropriate

siting of a Class VI well and prevent fluid movement that endangers a USDW. EPA notes that the

Director has the authority to deny a permit to any project that would violate state laws. 

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23670

Other EPA Comment Codes and Descriptions: 1610 1.3.1 Risks to USDWs 

Comment: AWWA recommends that EPA prohibit owner/operators from constructing carbon 

dioxide injection wells in sole source aquifers. Owner/operators should also be 

prohibited from ever injecting carbon dioxide into a formation that would result 

in the migration of the carbon dioxide to a point that is under a sole source 

aquifer. EPA should establish a minimum distance that needs to be provided 

between the closest geologic sequestration project and the location of any sole 

16
source aquifers. AWWA would recommend a 50 mile minimum; however, not being 

experts on the details of plume migration, AWWA recommends that EPA and DOE 

perform research on this topic to better assess what the regulatory requirement 

should be. Including these restrictions in the final geologic sequestration 

regulation would allow for the protection of drinking water aquifers that, if 

contaminated by carbon dioxide, could result in very significant and expensive 

issues for the drinking water utilities. 

Response: EPA believes that the extensive site characterization requirements for GS projects in the

final rule are protective of USDWs, including sole source aquifers. The GS rule, at §146.82(a)(5)

requires prospective owners or operators to submit information on all USDWs, which would include

sole source aquifers within the AoR. The GS rule also requires operators to submit extensive

information about the site, including the geologic characteristics of the injection and confining

zones, to demonstrate that the injected CO2 will remain within the target formation. The Director

must consider this information and the potential impact of the GS project on any sole source aquifers

when determining whether GS is acceptable at a given site. 

EPA agrees that, in many cases, UIC Directors will have extensive knowledge of which areas are

suitable for GS, but clarifies that it is the responsibility of Class VI permit applicants to demonstrate

the suitability of a particular site or formation. It is the responsibility of the Director to evaluate the

information collected and submitted by the owner or operator to determine whether a permit for GS

at the site is appropriate.

EPA is tracking other recent research on GS and USDW protection including the following studies

(which are available in the docket for the rulemaking):

• Smyth et al. (2008) reviewed modeling and laboratory experiments and field results from

groundwater studies conducted at SACROC, an ER site in west Texas where tens of millions of tons

of CO2 have been injected for over 30 years.

• Zheng et al. (2008) used more than 38,000 groundwater quality analyses from aquifers throughout

the US to perform reactive transport modeling of groundwater quality after the intrusion of CO2. The

model simulations indicate that aquifers containing more carbonate and clay minerals are less

vulnerable to CO2 intrusion, and that, while under certain conditions CO2 can potentially mobilize

metals present in the aquifer, mobilized amounts of the metals are always below health-based limits.

• Kharaka et al. (2009) conducted CO2 injection field tests in Montana and reported that shallowly

injected CO2 can affect the chemistry of shallow groundwater by decreasing pH and mobilizing rock

and soil ions. 

• Nicot (2008) modeled an injection roughly equivalent to 50 Mt CO2/year for 50 years in an area

that is hydrologically similar to the Gulf Coast Basin. Model results indicate an average water table

rise of approximately 1 meter with a minor increase in stream baseflow and a larger increase in

ground water evapotranspiration. 

ORD's National Center for Environmental Research awarded six Science To Achieve Results

(STAR) grants in the Fall of 2009 to recipients from major universities and institutions within the

scope of the "Integrated Design, Modeling and Monitoring of Geologic Sequestration of

Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water" research area. These

projects, which started in late 2009, include these lead institutions with specific topics of

investigation: Clemson University will study potential impacts to drinking water aquifers of CO2-

rich dissolved brines; the University of Illinois-Urbana will conduct research related to reducing

hydrologic and geochemical uncertainties associated with CO2 sequestration in deep, saline

17
reservoirs; the University of Texas at Austin will assess appropriate monitoring approaches at

geologic sequestration sites; the University of Utah will integrate design, monitoring, and modeling

of GS to assist in developing a practical methodology for characterizing risks to USDWs; Columbia

University will conduct laboratory experiments on shallow aquifer systems to improve understanding

of geochemical and microbiological reactions under low pH/high CO2 stress; and Princeton

University will develop a set of computational tools to model CO2 and brine movement associated

with GS.

Commenter Name: Edward Steadman Letter ID: 0220

Commenter Organization: The Energy and Environmental Research Center at the

University of North Dakota

Comment ID:

21590

Other EPA Comment Codes and Descriptions: 3300 2.2.1 Delineating the AoR/Modeling CO2

movement 

Comment: Page 43499. One would caution rule makers on putting too much faith into any one 

institution or any one method when studying potential impacts. Should not such 

information be provided by various technical sources? While the utility of 

models and laboratory data is recognized, their results should not supersede 

real-world experience, field-based data, and local knowledge. 

Response: EPA considered a wide range of information from laboratory, modeling, and field

research as it developed the requirements for GS wells. In addition to laboratory studies and

modeling research that provide relevant information on GS, the Agency is also involved in collecting

and analyzing GS project data and permit information from a variety of sources. Most notably, EPA

has evaluated UIC permits and reviewed operational data and information associated with the seven

regional carbon sequestration partnerships funded by the U.S. Department of Energy and coordinated

through the National Energy Technology Laboratory (NETL), and several international projects. In

addition to the information cited in the preamble to the proposed rule, EPA published a Notice of

Data Availability and Request for Comment (NODA) on August 31, 2009 (74 FR 44802), in which

the Agency described the preliminary 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. 

Regarding the suggestion that EPA give more weight to field data and experiential knowledge, EPA

notes that it continues to track ongoing field and laboratory research into all aspects of GS. For

example, EPA is tracking the operations and technical developments of more than three dozen smalland large-scale GS injection projects in the US and abroad. Also, since field experience and well

construction, injection, and monitoring information relevant to GS comes from operations that inject

acid gas or inject CO2 for ER, the Agency has conducted evaluations regarding these commercial

field operations and continues to track GS-relevant developments in these commercial operations.

The Agency will continue to track GS project developments and evaluate new and ongoing research

and information to ensure USDW protection. EPA is using an adaptive approach to regulating GS

under the UIC Program. Even after finalization of the GS regulation, the Agency plans to collect and

review 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 finalized requirements are appropriate or necessary.

EPA agrees that AoR modeling should be based on actual data collected on the site, including

detailed geologic data collected to characterize the injection zone, confining zone and any additional

18
zones, as required at 146.84(c)(1)(i). The Agency believes that the integration of site specific

information into a predictive multiphase computational model will ensure the best possible AoR

delineation. EPA also recognizes that modeling technology will continue to improve, and encourages

and expects owners or operators to use the best available multiphase computational models to

determine the AoR. Reliance on improved models will likely increase the accuracy and quality of the

AoR characterization, resulting in increased protection of USDWs from endangerment.

Commenter Name: Edward Steadman Letter ID: 0220

Commenter Organization: The Energy and Environmental Research Center at the

University of North Dakota

Comment ID:

21592

Other EPA Comment Codes and Descriptions: 3300 2.2.1 Delineating the AoR/Modeling CO2

movement 

Comment: Page 43500. Regarding the basis of some of the rules related to modeling Much 

has happened in the world of modeling CO2 injection and long-term storage since 

2005. Many of the key messages from the workshop upon which some of the 

statements on this topic are based may be long out of date. 

Response: EPA continues to review new and ongoing modeling studies, including those conducted

at national research laboratories, such as Lawrence Berkeley National Laboratories as well as data

from the DOE Partnership GS pilot projects where some of the most current models are being

developed and/or used. EPA published a Notice of Data Availability and Request for Comment on

August 31, 2009 (74 FR 44802), in which the Agency described two recent modeling studies by the

Lawrence Berkeley National Laboratory on the potential effects of CO2 injection on USDWs and

human health in the event that a GS project is not properly sited, operated, or managed. These

studies are in the rulemaking docket and on LBNL's website at

http://esd.lbl.gov/GCS/projects/CO2/index_CO2.html. Additionally, EPA continues to fund research

on ground water that will integrate experimental and modeling efforts with the objective of

evaluating the potential consequences of CO2 leaks from GS operations into ground water resources.

EPA is using an adaptive approach to regulating GS under the UIC Program. Even after finalization

of the GS regulation, EPA 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.

As described above, EPA recognizes that modeling technology will continue to improve, and

encourages and expects owners or operators to use the best available multiphase computational

models to determine the AoR. Reliance on improved models will likely increase the accuracy and

quality of the AoR characterization, resulting in increased protection of USDWs from endangerment.

Comment Code: 1820 1.4.1.1 Vulnerability Evaluation Framework (VEF) 

Individual Comments

Commenter Name: Anonymous2 Letter

19
ID: 0133

Commenter Organization: Sierra Club National Global Warming and Energy

Committee and Sierra Club California-Nevada Regional Conservation Committee on

Energy and Climate Change

Comment

ID: 21582

Comment: "Vulnerability Evaluation Framework": Expand the "Vulnerability Evaluation 

Framework" to include a multi-scaled classification scheme for adverse impacts 

associated with the capture and transportation of CO2 and the operational 

infrastructure involved in CO2 storage, such as pipelines, roads, buildings, and 

well construction. 

Response: The Agency clarifies that the VEF is intended to be a risk screening tool, but it is not a

required component of the GS site selection process. The UIC Class VI well permit application

requirements, including the minimum criteria for siting at §146.83, and the information requirements

at §146.82 provide the basis for determining whether a proposed GS site is geologically appropriate

and the proposed operations are technically viable, safe, and will not endanger USDWs. 

The GS rule provides flexibility to determine the suitability of a proposed site based on extensive,

site-specific data. The Director may consider some components of the VEF (e.g., information

regarding wells, faults, and pressure changes) when assessing the appropriateness of a site for GS;

however, the Director's permit approval determination is based on UIC Class VI requirements and

not the VEF. EPA clarifies that concerns about operational infrastructure (e.g., pipelines) have no

bearing on USDW protection and are outside of the scope of the GS rulemaking. 

Commenter Name: Anonymous2 Letter

ID: 0133

Commenter Organization: Sierra Club National Global Warming and Energy

Committee and Sierra Club California-Nevada Regional Conservation Committee on

Energy and Climate Change

Comment

ID: 21615

Comment: E. "Vulnerability Evaluation Framework" 

Recommendation E: Expand the "Vulnerability Evaluation Framework" to include a 

multi-scaled classification scheme for adverse impacts associated with the 

capture and transportation of CO2 and the operational infrastructure involved in 

CO2 storage, such as pipelines, roads, buildings, and well construction. 

The Sierra Club supports the EPA's use of the VEF approach to "systematically 

identify those conditions that may increase or decrease susceptibility to 

adverse impacts from GS"; we approve of the establishment of categories, 

thresholds, and flowcharts to aid administrative decision making processes(See: 

http://www.epa.gov/climatechange/emissions/downloads/VEFTechnical_Document_072408.pdf). It is understood that the vulnerability 

assessment is intended to be iterative and adaptive to new data. However, at the 

outset, Sierra Club urges the EPA to refine the binary vulnerability 

classification, which exhibits a flawed gap between the low and elevated levels 

in its current formulation. Most specifically, the taxonomy only allows for a 

finding of corrective action ("monitoring and mitigation procedures") to be 

applied in cases of an elevated vulnerability impact, and does not anticipate 

the rejection of a permit on the basis of a site's high vulnerability impact on 

human populations, ecosystems, and geospheres surrounding the proposed injection 

well sites. At the very minimum, a three-tiered classification of low, medium, 

20
and high vulnerability would trigger certain corrective actions at a medium 

level, and would result in the denial of a permit where there exists a high 

vulnerability level for legislatively protected human populations, conservation 

lands, endangered wildlife, and surrounding bodies of water other than protected 

USDWs. 

Secondarily, the Sierra Club urges the EPA to expand the VEF design to include 

"operational aspects of GS such as surface infrastructure (e.g. buildings, 

pipelines, well construction), and specific monitoring techniques to ensure the 

integrity of the GS system recommended." As the authors of the document 

conclude: "[T]hese elements need to be considered because they may play an 

important role in defining a project's overall vulnerability"[italics added]. 

Response: The Agency clarifies that the VEF is intended to be a risk screening tool, but it is not a

required component of the GS site selection process. The UIC Class VI well permit application

requirements, including the minimum criteria for siting at §146.83, and the information requirements

at §146.82 provide the basis for determining whether a proposed GS site is geologically appropriate

and the proposed operations are technically viable, safe, and will not endanger USDWs. 

EPA believes that requiring appropriate site characterization by the owner or operator and providing

an appropriate degree of flexibility to the Director to evaluate site-specific geologic data will afford

the greatest protection of USDWs. The issuance of a UIC Class VI permit is determined based on

evaluation of site-specific permit information pursuant to the requirements at §§146.82 and 146.83.

The Director may consider some components of the VEF (e.g., information regarding wells, faults,

and pressure changes) when assessing the appropriateness of a site for GS; however, the Director's

permit approval determination is based on UIC Class VI requirements and not the VEF. EPA

clarifies that concerns about operational infrastructure (e.g., pipelines) have no bearing on USDW

protection and are outside of the scope of the GS rulemaking. 

Commenter Name: Andrew Duguid Letter ID: 0226

Commenter Organization: Schlumberger Carbon Services Comment ID: 24005

Comment: 4. Schlumberger appreciates that the EPA crated the Vulnerability 

Evaluation Framework (VEF) and we fully support the use of a logical set 

of steps to address the vulnerabilities or risks associated with 

geologic carbon sequestration. However, we are concerned that the VEF 

is not the only method that may be successful for site evaluation and 

would like EPA to clarify that the VEF is one but not the only approach. 

Response: The Agency clarifies that the VEF is intended to be a risk screening tool, but it is not a

required component of the GS site selection process. The UIC Class VI well permit application

requirements, including the minimum criteria for siting at §146.83, and the information requirements

at §146.82 provide the basis for determining whether a proposed GS site is geologically appropriate

and the proposed operations are technically viable, safe, and will not endanger USDWs. 

EPA believes that requiring appropriate site characterization by the owner or operator and providing

an appropriate degree of flexibility to the Director to evaluate site-specific geologic data will afford

the greatest protection of USDWs. The issuance of a UIC Class VI permit is determined based on

evaluation of site-specific permit information pursuant to the requirements at §§146.82 and 146.83.

The Director may consider some components of the VEF (e.g., information regarding wells, faults,

21
and pressure changes) when assessing the appropriateness of a site for GS; however, the Director's

permit approval determination is based on UIC Class VI requirements and not the VEF. 

Comment Code: 1840 1.4.1.3 Other research 

Individual Comments

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23676

Comment: AWWA also recommends that EPA review the following reports that address the 

potential costs of treating source water that has lowered pH levels and/or 

increased concentrations of iron, minerals and other potential contaminants. 

- AWWA projects: 

o Managing Change and Unintended Consequences: Lead and Copper Rule Corrosion 

Control Treatment (WITAF) 

o Regulatory Risk Assessment for Arsenic in Water (WITAF) 

o Technology and Cost Review of the Proposed Arsenic Regulation (WITAF) 

- AwwaRF projects: 

o Adsorbent Treatment Technologies for Arsenic Removal (#2731) 

o Demonstration of Emerging Technologies for Arsenic Removal (#2661) 

o Implementation of Arsenic Treatment Systems Part 2: Design Considerations, 

Operation, and Maintenance (#2665) 

o Arsenic Removal by Iron-Modified Activated Carbon (#3158) 

o Subsurface Treatment For Arsenic Removal--Phases I and II (#3082) 

o Characterization and Performance of Filter Media for Manganese Control (#2951) 

o Occurrence of Manganese in Drinking Water and Manganese Control (#2863) 

o Advanced Processes for Simultaneous Arsenic and Manganese Removal (#2748) 

o Occurrence Survey of Boron and Hexavalent Chromium (#2759) 

o Integrated Water Treatment: Softening and Ultrafiltration (#2647) 

o Enhanced Reverse Osmosis Systems: Intermediate Treatment to Improve Recovery 

(#4061) 

o Membrane Treatment Of Impaired Irrigation Return (#4069) 

o Zero Liquid Discharge Desalination of Waters with High Organic Content (#4163) 

o Zero Liquid Discharge for Inland Desalination (#3010) 

o Comparison of Zinc vs Non-Zinc Corrosion Control for Lead and Copper (#4103) 

o Effect of Nitrification on Corrosion in the Distribution System (#4015 

Response: EPA acknowledges that there are potential risks associated with GS including the

potential for leakage of CO2 into USDWs which may result in the mobilization of substances that

could endanger USDWs or affect drinking water supplies and increase treatment costs. 

Recent research has focused on addressing this concern. EPA is funding research at the Lawrence

Berkeley National Laboratory (LBNL) on potential USDW impacts associated with mobilization of

trace elements. In the August 31, 2009, Notice of Data Availability and Request for Comment (74

FR 44802), EPA published the results of the study, which evaluated the potential for GS to cause

changes in ground water quality as a result of CO2 leakage and subsequent mobilization of trace

22
elements such as arsenic, barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium

(Birkholzer et al., 2008a). In the study, LBNL estimated the amount of trace elements from native

mineral species that could potentially be mobilized by the intrusion of CO2 and the potential ground

water concentrations that could result, to determine the potential for drinking water standards to be

exceeded. Results from this model simulation suggest that if CO2 were to leak into a shallow

aquifer, the potential for mobilization of lead and arsenic could be enhanced, causing increases in the

concentration of these trace elements in ground water. The Agency continues to monitor research

related to CO2 confinement, potential for CO2 leakage, and mobilization of trace elements. EPA also

examined potential methods for conducting treatment of water affected by a CO2 leak; this study is

presented in the final rulemaking docket. 

EPA clarifies that the purpose of the Class VI requirements is to minimize and mitigate

potential/identified risks through proper site characterization, well construction, operation,

monitoring, post-injection site care, and site closure. The rule at §146.82 requires owners or

operators to submit extensive data about a proposed GS site in order to eliminate sites with potential

for unacceptable fluid movement that could endanger USDWs. Operators must also develop and

follow an emergency and remedial response plan to address any adverse effects associated with the

GS operation at §146.94) and maintain financial responsibility to address contamination under

§146.85. 

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23677

Comment: The lack of good background data and inappropriate oil and gas well closures 

reflect inadequate regulatory oversight that can only get worse as regulatory 

agencies are asked to take on more activities related to climate change. Climate 

change adaptation and mitigation measures, such as geologic sequestration, may 

be delayed due to inadequate regulatory agency resources (e.g., number of staff 

and expertise). EPA needs to support significant research to reduce the 

uncertainties associated with climate change and afford better long-term 

planning decisions as water utilities and their customers are likely to feel a 

disproportionate impact due to anticipated adaptation and mitigation activities. 

EPA should also work in concert with other federal agencies to spur research 

into technologies that can convert carbon dioxide into inert or innocuous 

products. 

Response: EPA acknowledges that there may be technical and administrative challenges including

resource concerns, and will work closely with the states to assist them in resolving funding issues or

acquiring the resources, personnel, and training needed to address the unique technical challenges

associated with GS. Please see EPA's guidance for primacy agencies on implementing the GS rule,

which will be available on EPA’s website at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

While developing the GS regulation, EPA evaluated relevant GS research, including projects

conducted by the seven regional carbon sequestration partnerships funded by the U.S. Department of

Energy (DOE) and coordinated through the National Energy Technology Laboratory (NETL), and

several international projects. Additionally, EPA's Office of Water continues to fund research at the

Lawrence Berkeley National Laboratory examining the effects of CO2 interaction on ground water

aquifers and any potential mobilization of trace elements that may occur. EPA is communicating

with other research organizations and academic institutions including, among others, Princeton

University, Massachusetts Institute of Technology, and Montana State University, where specific

research on geologic sequestration, injection well materials, and CO2 monitoring techniques is in

23
progress. EPA is also working with DOE, USGS, and others to identify tools and training techniques

that will provide GS permitting assistance and technical expertise as appropriate. Additionally, EPA's

Office of Research and Development (ORD) is undertaking multiple research efforts on GS. Topics

of research include bolstering different default thermodynamic databases to include more

comprehensive information on aqueous complexes and solid-phases that contain

carbonate/bicarbonate and toxic elements for which EPA has a listed MCL (maximum concentration

level) for safe drinking water. 

ORD's National Center for Environmental Research (NCER) awarded six Science To Achieve

Results (STAR) grants in the Fall of 2009 to recipients from major universities and institutions

within the scope of the "Integrated Design, Modeling and Monitoring of Geologic Sequestration of

Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water" research area. These

projects, which started in late 2009, include these lead institutions with specific topics of

investigation: Clemson University will study potential impacts to drinking water aquifers of CO2-

rich dissolved brines; the University of Illinois-Urbana will conduct research related to reducing

hydrologic and geochemical uncertainties associated with CO2 sequestration in deep, saline

reservoirs; the University of Texas at Austin will assess appropriate monitoring approaches at

geologic sequestration sites; the University of Utah will integrate design, monitoring, and modeling

of GS to assist in developing a practical methodology for characterizing risks to USDWs; Columbia

University will conduct laboratory experiments on shallow aquifer systems to improve understanding

of geochemical and microbiological reactions under low pH/high CO2 stress; and Princeton

University will develop a set of computational tools to model CO2 and brine movement associated

with GS.

EPA is using an adaptive approach to regulating GS under the UIC Program. Even after finalization

of the GS regulation, the Agency plans to collect and review 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.

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21675

Other EPA Comment Codes and Descriptions: 4655 2.6.5.1 Plume tracking

techniques/geophysical methods (seeking comment) 

Comment: HEI and its affiliated companies in BP have significant and highly relevant 

experience around monitoring of the subsurface and the surface. For many 

decades, BP has been effectively employing a number of monitoring technologies 

to ensure the safety and integrity of its customary oil and gas operations, 

including CO2 EOR-related operations since the 1970’s in West Texas and Alaska. 

Notably, since 2004 BP has been operating the In Salah, Algeria, CO2 storage 

project where BP (and partners) has been storing around 1 million tones CO2 per 

year in a deep saline formation close to a producing gas field. The In Salah CO2 

Storage project also incorporates a research project to test CO2 storage 

monitoring technologies with a program that is much more extensive than would be 

appropriate for a commercial project. At In Salah, BP is testing new 

technologies (such as satellite imagery and micro-seismic) and conventional 

oilfield technologies (such as tracers and conventional 3D seismic) to compare 

and contrast results as the partnership endeavors to design and develop 

monitoring technologies and methodologies that are reliable and cost-effective, 

24
given the expectation of future commercial application. 

Before initiating injection at In Salah, BP conducted a thorough assessment of 

potential leakage paths at the site; BP then tailored the monitoring program to 

address those site-specific risks. There are two other monitored, industrialscale CO2 injection projects in the world (at Sleipner and Weyburn) and the 

site-specific nature of monitoring requirements is demonstrated by comparing 

these three CO2 storage projects - monitoring that works well at one location 

may not work at all in another location. 

Response: EPA continues to track ongoing field and laboratory research into all aspects of GS,

including subsurface CO2 monitoring. The Agency is tracking the operations and technical

developments of more than three dozen small- and large-scale GS injection projects in the US and

abroad. Also, since field experience and well construction, injection, and monitoring information

relevant to GS comes from operations that inject acid gas or inject CO2 for ER, the Agency has

conducted evaluations regarding these commercial field operations and continues to track GSrelevant developments in these commercial operations.

Additionally, EPA ORD's National Center for Environmental Research (NCER) awarded six Science

To Achieve Results (STAR) grants in the Fall of 2009 to recipients from major universities and

institutions within the scope of "Integrated Design, Modeling and Monitoring of Geologic

Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water." In one

project, the University of Texas at Austin will assess appropriate monitoring approaches at geologic

sequestration sites.

Regarding the development of monitoring and testing plans, EPA believes that testing and

monitoring plans should be based on site-specific information, similar to the examples described by

the commenter, and believes that flexibility is important in developing and implementing a

monitoring plan that is appropriately tailored for a specific GS site. The purpose of the requirement

at §146.90 to develop site-specific testing and monitoring plans is to ensure that the monitoring

performed at a site is appropriate for site operational conditions and the geologic setting. EPA

believes that this is the best approach for addressing potential risks at GS sites. These flexible

provisions in the monitoring requirements for Class VI wells enable the owner or operator to tailor

monitoring programs to the specific needs of each project in consultation with the Director.

The final regulation provides for flexibility in: 1) methodologies used to collect these data, 2) the

spatial resolution at which the data should be collected, and 3) how often the data should be

collected. The number and placement of monitoring wells will be based on site-specific information

such as the calculated AoR, injection rate and volume, site geology, baseline data, and the presence

of artificial penetrations within the AoR. In some instances, there may be a limited number of

options for complying with EPA's minimum requirements. For example, monitoring for geochemical

changes will require use of monitoring wells and collection of groundwater samples for chemical

analysis. Many options currently exist for complying with other requirements, such as tracking the

position of the plume and pressure front within the injection zone.

Flexibility is also provided regarding how to monitor for the specific data required by the final rule.

The testing and monitoring plan is developed by the owner or operator in consultation with the

Director and is designed to ensure that a detailed, Director-approved document describing how

monitoring will be conducted during the lifetime of the project exists. EPA is developing guidance

on testing and monitoring to assist owners or operators and Directors in evaluating requirements

25
under §146.90, including proposed monitoring plans. The guidance describes available technologies

and recommended approaches for implementing a testing and monitoring plan, including preoperational 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 can be found on EPA’s website at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21720

Other EPA Comment Codes and Descriptions: 4655 2.6.5.1 Plume tracking

techniques/geophysical methods (seeking comment) 

Comment: BP has significant and highly relevant experience around monitoring of the 

subsurface and the surface. For many decades, BP has been effectively employing 

a number of monitoring technologies to ensure the safety and integrity of its 

customary oil and gas operations, including CO2 EOR-related operations since the 

1970’s in West Texas and Alaska. Notably, since 2004 BP has been operating the 

In Salah, Algeria, CO2 storage project where BP (and partners) has been storing 

around 1 million tones CO2 per year in a deep saline formation close to a 

producing gas field. The In Salah CO2 Storage project also incorporates a 

research project to test CO2 storage monitoring technologies with a program that 

is much more extensive than would be appropriate for a commercial project. At In 

Salah, BP is testing new technologies (such as satellite imagery and microseismic) and conventional oilfield technologies (such as tracers and 

conventional 3D seismic) to compare and contrast results as the partnership 

endeavors to design and develop monitoring technologies and methodologies that 

are reliable and cost-effective, given the expectation of future commercial 

application. 

Before initiating injection at In Salah, BP conducted a thorough assessment of 

potential leakage paths at the site; BP then tailored the monitoring program to 

address those site-specific risks. There are two other monitored, industrialscale CO2 injection projects in the world (at Sleipner and Weyburn) and the 

site-specific nature of monitoring requirements is demonstrated by comparing 

these three CO2 storage projects - monitoring that works well at one location 

may not work at all in another location. 

Response: EPA continues to track ongoing field and laboratory research into all aspects of GS,

including subsurface CO2 monitoring. The Agency is tracking the operations and technical

developments of more than three dozen small- and large-scale GS injection projects in the US and

abroad. Also, since field experience and well construction, injection, and monitoring information

relevant to GS comes from operations that inject acid gas or inject CO2 for ER, the Agency has

conducted evaluations regarding these commercial field operations and continues to track GSrelevant developments in these commercial operations.

Additionally, EPA ORD's National Center for Environmental Research (NCER) awarded six Science

To Achieve Results (STAR) grants in the Fall of 2009 to recipients from major universities and

institutions within the scope of "Integrated Design, Modeling and Monitoring of Geologic

Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water." In one

26
project, the University of Texas at Austin will assess appropriate monitoring approaches at geologic

sequestration sites.

Regarding the development of monitoring and testing plans, EPA believes that testing and

monitoring plans should be based on site-specific information, and believes that flexibility is

important in developing and implementing a monitoring plan that is appropriately tailored for a

specific GS site. The purpose of the requirement at §146.90 to develop site-specific testing and

monitoring plans is to ensure that the monitoring performed at a site is appropriate for site

operational conditions and the geologic setting. EPA believes that this is the best approach for

addressing potential risks at GS sites. These flexible provisions in the monitoring requirements for

Class VI wells enable the owner or operator to tailor monitoring programs to the specific needs of

each project in consultation with the Director.

The final regulation provides for flexibility in: 1) methodologies used to collect these data, 2) the

spatial resolution at which the data should be collected, and 3) how often the data should be

collected. The number and placement of monitoring wells will be based on site-specific information

such as the calculated AoR, injection rate and volume, site geology, baseline data, and the presence

of artificial penetrations within the AoR. In some instances, there may be a limited number of

options for complying with EPA's minimum requirements. For example, monitoring for geochemical

changes will require use of monitoring wells and collection of groundwater samples for chemical

analysis. Many options currently exist for complying with other requirements, such as tracking the

position of the plume and pressure front within the injection zone.

Flexibility is also provided regarding how to monitor for the specific data required by the final rule.

The testing and monitoring plan is developed by the owner or operator in consultation with the

Director and is designed to ensure that a detailed, Director-approved document describing how

monitoring will be conducted during the lifetime of the project exists. EPA is developing guidance

on testing and monitoring to assist owners or operators and Directors in evaluating requirements

under §146.90, including proposed monitoring plans. The guidance describes available technologies

and recommended approaches for implementing a testing and monitoring plan, including preoperational 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 can be found on EPA’s website at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Craig Hart Letter ID: 0261

Commenter Organization: Alston & Bird LLP Comment ID: 22982

Comment: This letter recommends that EPA provide for streamline provisions for permitting 

small-scale CCS research and test injections under the SDWA in order to 

facilitate future CCS research and development efforts. A streamline permitting 

procedures would focus regulatory resources appropriately on large-scale 

injections, rather than on small injections that pose little or no risk to the 

environment. 

The EPA's proposed rule for CCS injections under the SDWA released in July 2008 

contains no provision for small-scale test injections performed prior to full 

permitting for purposes of research or characterizing the geology of a proposed 

well. The preamble to the proposed rule does, however, provide that Class V 

27
experimental well classification will remain available for those pilot-projects 

that continue to qualify under Class V guidelines. [FN1] 

However, as described in this letter, there is evidence that the Class V 

experimental well provision was disfavored by Phase II project proponents. As 

described below, most Phase II projects sought to avoid permitting under Class 

V. Also, the lack of uniformity inherent in the SDWA UIC program poses 

challenges for the research community in the permitting area.[FN2] I urge EPA to 

take the opportunity to consider research needs in developing a regime for 

permitting CO2 injections for CCS purpose under Class VI. 

[FN1] U.S. Environmental Protection Agency, VIC Program Guidance No. 83, "Using 

the Class V Experimental Technology Well Classification for Pilot Geologic 

Sequestration Projects," March 1, 2007, available at 

http://www.epa.gov/safewater/uic/pdfsj guide_uic_carbonsequestrationJinalO307.pdf. 

[FN2]Under the UIC program, some states have primacy for all classes of wells, 

some states have primacy for Class II wells, some states have primacy for all 

classes of wells except Class II, and some state UIC programs are operated by 

the regional U.S. EPA office. Depending upon the class of permit, authority is 

held by oil and gas divisions or environmental protection agencies within 

states. These agencies may take differing approaches to the protection of 

drinking water under the SDWA. Each project will therefore involve different 

regulators and permitting strategies depending upon the regulatory framework 

governing the particular project. 

Response: The final rule allows owners or operators to continue using the Class V experimental well

permit process for small-scale projects that are experimental in nature. EPA believes that the Class V

and Class VI permitting requirements are necessary to protect USDWs from endangerment because

they are based on site-specific and project-specific information, including CO2 volume. EPA

believes that the requirements for GS owners or operators are flexible enough to take into account

plant operating data, including the volume to be injected.

EPA acknowledges that there may be technical and administrative challenges including resource

concerns, and will work closely with the states to assist them in resolving funding issues or acquiring

the resources, personnel, and training needed to address the unique technical challenges associated

with GS. Please see EPA's guidance for primacy agencies on implementing the GS rule, which will

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

Comment Code: 1850 1.4.2 CO2 GS Field Research 

Individual Comments

Commenter Name: William Kovacs Letter ID: 0148

Commenter Organization: U.S. Chamber of Commerce Comment ID: 21769

Comment: 2. Need for Full-Scale Pilot Projects 

28
Globally, only four full-scale CCS projects exist, and none of them capture CO2 

from a coal-fired power plant. The International Energy Agency notes that at 

least 20 large-scale demonstration projects will need to be in planning by 2010 

and in operation by 2020 to have any impact on climate change policy planning. 

EPA should ensure that this timetable is considered before implementing its 

final rule. 

Response: EPA clarifies that controlling the pace of GS deployment is outside of the UIC program's

authority under the Safe Drinking Water Act and outside the scope of this rulemaking. The UIC

requirements are designed to ensure that, where GS is employed, it is done in a manner that protects

USDWs from endangerment.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23385

Other EPA Comment Codes and Descriptions: 1610 1.3.1 Risks to USDWs 

Comment: APPA strongly supports private and DOE/NETL geologic sequestration demonstration 

projects to tell us more about the technical viability of the separation 

technology and the scaling up of geologic sequestration. Further, these projects 

must also support any geosequestration or GS research projects that would better 

enable us to know more about the USDWs and protection of that critical resource. 

The "location is everything" is a critical presumption for the reader of our 

comments on the proposed UIC rule. In some locations geosequestration will be an 

optimal technology that makes sense for those future coal plants. In other 

locations, the type of rock, the lack of trapping mechanisms or proximity to 

underground faults, seismic risks or other 

Response: As described above, EPA is tracking continuing research on CCS conducted by other

federal agencies.

EPA agrees that further research will assist with the transition to commercial-scale GS. As part of its

adaptive rulemaking approach, The Agency plans, every six years, to collect and review data on GS

projects to determine whether the appropriate amount and types of information and appropriate

documentation are being collected, and to determine if modifications to the requirements are

appropriate or necessary.

While developing the GS regulation, EPA evaluated relevant GS research, including projects

conducted by the seven Regional Carbon Sequestration Partnerships funded by DOE and coordinated

through the National Energy Technology Laboratory (NETL), and several international projects.

EPA published a Notice of Data Availability and Request for Comment (NODA) on August 31,

2009 (74 FR 44802), in which the Agency presented the results of research at three DOE partnership

sites (in Escatawpa, Mississippi; the Aneth Field in Paradox Basin, southeast Utah; and the Pump

Canyon Site, New Mexico). 

In the NODA and Request for Comment, EPA described two modeling studies by the Lawrence

Berkeley National Laboratory on the potential effects of CO2 injection on ground water and

surrounding formations to determine the potential for impacts on USDWs and human health in the

event that a GS project is not properly sited, operated, or managed. In one study, LBNL used a

comprehensive computational model to evaluate the potential impact of CO2 leaking from deep GS

sites on the concentrations of trace elements in USDWs (Birkholzer et al., 2008a). In the other,

29
LBNL studied a hypothetical, future scenario of GS in a sedimentary basin to demonstrate the

potential for basin-scale hydrologic impacts of CO2 storage (Birkholzer et al., 2008b). EPA has also

examined potential methods for conducting treatment of water affected by a CO2 leak; this study is

presented in the final rulemaking docket. 

EPA continues to fund research in this area. In December 2009, EPA awarded a STAR grant to

Clemson University to investigate the potential for GS to affect USDWs. The research will involve

laboratory experiments and modeling simulations to investigate the fate of dissolved CO2 in

underground geologic formations and to determine possible risks associated with the dissolution of

CO2 in underground aquifers. Other projects funded by the STAR grants include: the University of

Illinois-Urbana will conduct research related to reducing hydrologic and geochemical uncertainties

associated with CO2 sequestration in deep, saline reservoirs; the University of Texas at Austin will

assess appropriate monitoring approaches at geologic sequestration sites; the University of Utah will

integrate design, monitoring, and modeling of GS to assist in developing a practical methodology for

characterizing risks to USDWs; Columbia University will conduct laboratory experiments on shallow

aquifer systems to improve our understanding of geochemical and microbiological reactions under

low ph/high CO2 stress; and Princeton University will develop a set of computational tools to model

CO2 and brine movement associated with GS.

Commenter Name: Saba Tahmassebi Letter ID: 0218

Commenter Organization: Oklahoma Department of Environmental Quality

(DEQ)

Comment ID:

21561

Other EPA Comment Codes and Descriptions: 1510 1.2.2.3 Need for additional study 

Comment: 1. Delay the proposed schedule for the implementation of the final rule. With 

the current state of technology, there does not appear to exist enough data to 

determine whether geologic sequestration of carbon dioxide can be accomplished 

in a safe manner. In fact, in its preamble to the proposed rule, EPA states 

that conducting large volume carbon storage tests are necessary to demonstrate 

that large-scale CO2 injection and storage can be achieved safely and 

economically. The preamble also suggests that the DOE-sponsored "Deployment 

Phase" of research is likely to provide the necessary data to make this 

determination. The Deployment Phase is scheduled to be completed in 2017. 

Therefore, EPA will not have enough data to adequately determine that largescale implementation of the rule is safe until after 2017 when the data is 

gathered and analyzed. Oklahoma DEQ recommends that EPA postpone finalizing the 

rule until after 2017 to include the results of the pilot studies. Without the 

benefit of considering the results of these studies, the safety of geologic 

sequestration activities will remain questionable. In the meantime, EPA may 

Response: EPA agrees that continued research will be integral to development of GS technology,

but disagrees that the Agency should wait for the DOE pilot studies to be complete before finalizing

the GS rule. EPA believes that establishing a regulatory framework for the future development and

deployment of CCS technology protects USDWs from endangerment and will not impede industry

adoption of CCS. 

EPA believes that sufficient research has been conducted and sufficient data gathered to proceed

with rule promulgation. While developing the GS regulation, EPA evaluated relevant GS research,

including projects conducted by the seven regional carbon sequestration partnerships funded by the

U.S. Department of Energy (DOE) and coordinated through the National Energy Technology

30
Laboratory (NETL), and several international projects. Additionally, EPA's Office of Water

continues to fund research at the Lawrence Berkeley National Laboratory examining the effects of

CO2 interaction on ground water aquifers and any potential mobilization of trace elements that may

occur. EPA is communicating with other research organizations and academic institutions including,

among others, Princeton University, Massachusetts Institute of Technology, and Montana State

University, where specific research on geologic sequestration, injection well materials, and CO2

monitoring techniques is in progress. EPA is also working with DOE, USGS, and others to identify

tools and training techniques that will provide GS permitting assistance and technical expertise as

appropriate. Additionally, EPA's Office of Research and Development (ORD) is undertaking

multiple research efforts on GS. Topics of research include bolstering different default

thermodynamic databases to include more comprehensive information on aqueous complexes and

solid-phases that contain carbonate/bicarbonate and toxic elements for which EPA has a listed

maximum contaminant level (MCL) for safe drinking water. 

ORD's National Center for Environmental Research (NCER) awarded six Science To Achieve

Results (STAR) grants in the Fall of 2009 to recipients from major universities and institutions

within the scope of the "Integrated Design, Modeling and Monitoring of Geologic Sequestration of

Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water" research area. These

projects, which started in late 2009, include these lead institutions with specific topics of

investigation: Clemson University will study potential impacts to drinking water aquifers of CO2-

rich dissolved brines; the University of Illinois-Urbana will conduct research related to reducing

hydrologic and geochemical uncertainties associated with CO2 sequestration in deep, saline

reservoirs; the University of Texas at Austin will assess appropriate monitoring approaches at

geologic sequestration sites; the University of Utah will integrate design, monitoring, and modeling

of GS to assist in developing a practical methodology for characterizing risks to USDWs; Columbia

University will conduct laboratory experiments on shallow aquifer systems to improve understanding

of geochemical and microbiological reactions under low pH/high CO2 stress; and Princeton

University will develop a set of computational tools to model CO2 and brine movement associated

with GS.

EPA is using an adaptive approach to regulating GS under the UIC Program. Even after finalization

of the GS regulation, the Agency plans to collect and review data every six years on GS projects to

determine whether the appropriate amount and types of information and documentation are being

collected, and to determine if modifications to the requirements are necessary.

Commenter Name: Neeraj Gupta Letter ID: 0229

Commenter Organization: Battelle Energy Technology (BET) Comment ID: 21812

Other EPA Comment Codes and Descriptions: 2048 1.5.2.4 Oppose Class VI/ Support Class V

experimental technology well 

Comment: Encouraging Innovation and Experimental Projects - We believe that USEPA 

recognizes that many facets of GS site selection, implementation, and monitoring 

are still under technological assessment and innovation phase. Many of the 

concepts and technological options are being evaluated under current field 

demonstration programs by Regional Partnerships and other projects across the 

world. The success of these existing and future experimental projects is 

heavily dependent on permitting process being as simple as possible. USEPA UIC 

Guidance 83 allowing the use of Class V experimental wells has been a very 

useful mechanism for facilitating experimental projects. In fact, if the 

proposed Class Vi framework was to be applied to smaller-scale tests currently 

31
underway, it is our belief that many projects would have financial, logistical, 

or technical difficulties in moving to field stage. With the proposed 

regulation in the public comment phase, MRCSP has already observed that the 

permit regulations for even small-scale field tests (such as MRCSP East Bend 

site and AEP Mountaineer Project) are becoming too onerous compared to similar 

projects permitted prior to the issuance of draft regulations. For example, the 

post-injection monitoring durations have become much longer with the regulators 

citing the draft regulation as a basis for requirements. Such a trend will 

certainly adversely affect future experimental projects and lead to less new 

data being available to all stakeholders. We strongly encourage EPA to 1) 

continue the existing option for using Class V experimental well permits option 

and/or specifically allow for a more simplified and less onerous permitting 

requirements for such project. 

Response: EPA acknowledges the value of the DOE pilot projects and resultant data and

information generated by such projects. EPA has evaluated permits and reviewed operational data

and information associated with the seven RCSPs funded by the U.S. Department of Energy and

coordinated through the National Energy Technology Laboratory (NETL). 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. 

The GS final rule does not affect an owner or operator’s ability to apply for a Class V experimental

technology well permit for projects that are of an experimental nature, i.e., to test GS technologies.

The Agency is also tracking operation and technical developments of more than three dozen smalland large-scale GS injection projects in the United States and abroad. EPA meets regularly with

DOE to discuss its research initiatives, project developments, and "best practices." 

EPA agrees with commenters that flexibility to address new research is important. Even after

finalizing the rule, 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.

Commenter Name: Abbie Krebsbach Letter ID: 0235

Commenter Organization: Montana-Dakota Utilities Co. Comment ID: 23177

Other EPA Comment Codes and Descriptions: 1250 1.1.1.4 Flexibility is needed (performancebased standards); 1410 1.2.1 Comments in support of EPA/rulemaking 

Comment: Montana-Dakota strongly supports research and development efforts underway to 

facilitate commercial-scale CO2 capture and sequestration (CCS) projects, and 

shows this support specifically through its active membership in the Plains CO2 

Regional (PCOR) Partnership. Led by the EERC and assisted by its members, PCOR 

and has developed and is currently carrying out two CO2 geologic sequestration 

projects designed to demonstrate the effectiveness of CO2 geologic 

sequestration. As these efforts increase, it is necessary to develop clear, 

flexible and appropriately tailored regulations to facilitate the development of 

and spur investment in carbon capture and sequestration technology. The proposed 

32
rule assists with creating additional certainty in approaching GS project 

development, however there are some concerns that need to be addressed. MontanaResponse: EPA acknowledges the value of the DOE pilot projects and resultant data and

information generated by such projects. EPA has evaluated permits and reviewed operational data

and information associated with the seven RCSPs funded by the U.S. Department of Energy and

coordinated through the National Energy Technology Laboratory (NETL). 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 agrees that flexibility to address new research is important. Even after finalizing the rule, the

Agency plans to collect and review data every six years on GS projects, including research by the

DOE Partnerships, 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.

EPA agrees that the implementation of the GS rule in a manner that ensures protection of USDWs

from endangerment is important to establishing a foundation for further advances in the field of CO2

GS. EPA acknowledges the need for regulatory certainty: the final GS requirements provide a level

of certainty by setting forth unique requirements for GS. These requirements include: the tailored

AoR delineation process at §146.84, the types of monitoring appropriate to GS projects (§146.90)

and the post-injection site care process (§146.93). For additional information on these requirements,

please also see the discussion of EPA’s Final Regulatory Approach in the preamble to the final GS

rule.

EPA agrees that an adaptive and flexible approach is appropriate. To protect USDWs from

endangerment and meet the potentially fast pace of GS deployment, EPA is using an adaptive

approach to regulating CO2 injection for 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. An adaptive approach will allow regulatory development to proceed in

time to meet the current and future demands for Class VI permits while EPA continues to gather data

from pilot projects and other research as it becomes available.

Comment Code: 1852 1.4.2.1 DOE Regional Carbon Sequestration Partnerships 

Individual Comments

Commenter Name: Karl R. Moor Letter ID: 0109

Commenter Organization: Southern Company, on behalf of Edison Electric

Institute (EEI)

Comment ID:

22010

Comment: As I noted, Southern has begun evaluating geologic storage sites including our 

demonstration injection project in Mississippi. The purpose of this project, 

which is part of the Southeast Carbon Sequestration Regional Partnership, is to 

learn more about the siting of geologic storage. Carbon capture and storage is 

33
not yet a commercial-scale technology, and projects like ours are crucial for 

expanding our technical expertise. To this end, EEI asks EPA to ensure that the 

final regulations can consider and, as appropriate, incorporate data developed 

through this and other carbon capture and storage demonstration projects. EEI 

and I appreciate the opportunity to provide additional input to this rulemaking 

process. EEI and its members are confident that we can work with EPA and other 

stakeholders to create a clear and flexible regulatory scheme that achieves two 

important goals: the protection of underground sources of drinking water and 

the promotion of carbon capture and storage technology and projects. 

Response: EPA acknowledges the value of the DOE pilot projects and resultant data and

information generated by such projects. EPA has evaluated permits and reviewed operational data

and information associated with the seven RCSPs funded by the U.S. Department of Energy and

coordinated through the National Energy Technology Laboratory (NETL). 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 agrees that flexibility to address new research is important. Even after finalizing the rule, the

Agency plans to collect and review data every six years on GS projects, including research by the

DOE Partnerships, to determine whether the appropriate amount and types of information and

appropriate documentation are being collected, and to determine if modifications to the requirements

are appropriate or necessary.

Commenter Name: Skiles Boyd Letter ID: 0160

Commenter Organization: DTE Energy Comment ID: 21266

Comment: FLEXIBILITY 

Recognizing that large scale sequestration demonstration projects are still in 

the planning and development stages, it is important for EPA to build in 

flexibility to these regulations to incorporate additional knowledge gained from 

these demos. DTE Energy participates in DOE’s Midwest Regional Carbon 

Sequestration Partnership (MRCSP) and was a host partner for a small scale 

injection demonstration near Gaylord, Michigan. Ten thousand tons of CO2, 

captured from one of our gas processing plants, was injected over a two week 

period in February and March 2008. Data analysis is closely confirming model 

predictions about the behavior of CO2 in the formation. Monitoring and data 

interpretation are still ongoing. Approval has recently been granted to 

increase the injection to fifty thousand tons of CO2. Although this is small 

scale, as a coal based electric utility, we are encouraged by the progress made 

to date with this demonstration. However, there are other pieces to the puzzle 

Response: EPA acknowledges the value of the DOE pilot projects and resultant data and

information generated by such projects. EPA has evaluated permits and reviewed operational data

and information associated with the seven RCSPs funded by the U.S. Department of Energy and

coordinated through the National Energy Technology Laboratory (NETL). 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

34
project in Paradox Basin, Southeast Utah; and the Pump Canyon Site, New Mexico.

EPA ORD's National Center for Environmental Research (NCER) awarded six Science To Achieve

Results (STAR) grants in the Fall of 2009 to recipients from major universities and institutions

within the scope of the "Integrated Design, Modeling and Monitoring of Geologic Sequestration of

Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water" research area. These

projects, which started in late 2009, include these lead institutions with specific topics of

investigation: Clemson University will study potential impacts to drinking water aquifers of CO2-

rich dissolved brines; the University of Illinois-Urbana will conduct research related to reducing

hydrologic and geochemical uncertainties associated with CO2 sequestration in deep, saline

reservoirs; the University of Texas at Austin will assess appropriate monitoring approaches at

geologic sequestration sites; the University of Utah will integrate design, monitoring, and modeling

of GS to assist in developing a practical methodology for characterizing risks to USDWs; Columbia

University will conduct laboratory experiments on shallow aquifer systems to improve understanding

of geochemical and microbiological reactions under low pH/high CO2 stress; and Princeton

University will develop a set of computational tools to model CO2 and brine movement associated

with GS.

The Agency is also tracking operation and technical developments of more than three dozen smalland large-scale GS injection projects in the United States and abroad. EPA meets regularly with

DOE to discuss its research initiatives, project developments, and "best practices." 

Even after finalizing the rule, 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.

Commenter Name: Sandi Tabor Letter ID: 0162

Commenter Organization: Lignite Energy Council (LEC) Comment ID: 21308

Comment: 2 Plains CO2 Reduction (PCOR) Partnership is a mUltiyear collaboration of over 

80 U.S. and Canadian stakehoiders that is laying the groundwork for practical 

and enVironmentally sound carbon dioxide (C02) sequestration projects in the 

heartland of North America, inclUding all or part of nine U.S. states and four 

Canadian provinces within the centrai interior of North America. [On line 

Available] http://www.undeerc.org/pcor/default.asp, Sept. 12,2008 

3 Id. From the fall of 2005 to the fall of 2009, the PCOR Partnership will be 

developing and carrying out four field validation projects in the PCOR 

Partnership region. These four field validation projects are designed to 

demonstrate the effectiveness of C02 sequestration in different settings and 

under different conditions. The PCOR Partnership field validation projects are 

among three dozen field validation projects that will occur in North America as 

part of Phase II of the U.S. Department of Energy Regional Carbon Sequestration 

Partnership Program. In the fail of 2007, the Partnership began developing two 

commercial- scale, long-term field demonstration projects for geologic C02 

sequestration. The PCOR Partnership commercial-scale sequestration field 

demonstrations are scheduled to run until 2017 and are among the several largescale geologic demonstration projects that will occur in North America as part 

of Phase ill of the U.S. Department of Energy. The region is also the site of 

35
the Weyburn geoiogic sequestration project since 2002. 

Response: EPA acknowledges the value of the DOE pilot projects and resultant data and

information generated by such projects. EPA has evaluated permits and reviewed operational data

and information associated with the seven RCSPs funded by the U.S. Department of Energy and

coordinated through the National Energy Technology Laboratory (NETL). 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. The Agency will

continue to track GS project developments and evaluate new and ongoing research and information

to ensure USDW protection.

Even after finalizing the rule, the Agency plans to collect and review data every six years on GS

projects, including data generated by the partnerships, to determine whether the appropriate amount

and types of information and appropriate documentation are being collected, and to determine if

modifications to the requirements are appropriate or necessary.

Commenter Name: Quinlan J. Shea Letter ID: 0177

Commenter Organization: Edison Electric Institute Comment ID: 23568

Other EPA Comment Codes and Descriptions: 2400 1.8 Comments on EPA's adaptive rulemaking

process 

Comment: iv. Maintaining ability to incorporate new information. Any regulatory regime 

must be sufficiently flexible to adapt to new information. Indeed, regulation 

of ongoing GS "pilot" projects under the existing UIC regulations for Class I or 

V wells has been positive. EPA must take great care moving to a new or 

different regulatory framework while projects designed to gain more 

technological certainty, as well as the increased certainty about appropriate 

risk management solutions for CCS projects that would likely follow, are 

ongoing. Given that EPA has decided to move forward with GS-specific 

regulations, EEI urges the Agency to develop a framework that can consider and, 

as appropriate, incorporate data developed through CCS demonstration projects 

and the activities of the Department of Energy‘s Regional Carbon Sequestration 

Partnerships. 

Response: EPA agrees that an adaptive approach to the UIC GS rulemaking is appropriate. The

Agency plans to use such an approach to ensure that USDWs are protected from endangerment and

meet the potentially fast pace of GS deployment. EPA believes that an adaptive approach will allow

regulatory development to proceed in time to meet the current and future demand for Class VI

permits while recognizing the need to: continue to gather data from pilot projects and other research

as it becomes available; and to enhance understanding of the technical and administrative aspects of

GS deployment, operation, and technology developments. 

EPA plans, every six years, to collect and review data on GS projects, including the DOE Regional

Carbon Sequestration Partnership 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.

36
Commenter Name: Christopher Murray Letter ID: 0207

Commenter Organization: Pacific Northwest National Laboratory Comment ID: 22430

Comment: This response provides recommended changes to the EPA proposed rule on 

underground injection control on CO2 for geologic sequestration (GS). Staff 

scientists at Pacific Northwest National Laboratory (PNNL) have extensive 

experience in research, development and deployment of GS. A dozen GS sites 

throughout the U.S. have been modeled by our staff through projects supported by 

the Department of Energy and industrial partnerships. This modeling supports site 

selection and permitting activities. We have also been involved in comprehensive 

GS projects, from conceptualization to site selection to design to deployment, 

including long-term monitoring. Based on this experience, we are well positioned 

to of fer constructive comments for the proposed EPA rules for permitting GS 

sites. 

Response: EPA acknowledges the value of the DOE pilot projects and resultant data and

information generated by such projects. EPA has evaluated permits and reviewed operational data

and information associated with the seven RCSPs funded by the U.S. Department of Energy and

coordinated through the National Energy Technology Laboratory (NETL). 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. The Agency will

continue to track GS project developments and evaluate new and ongoing research and information

to ensure USDW protection.

Commenter Name: Neeraj Gupta Letter ID: 0229

Commenter Organization: Battelle Energy Technology (BET) Comment ID: 21809

Other EPA Comment Codes and Descriptions: 1000 1. General and Administrative Comments 

Comment: Introduction and Background 

This document summarizes review and comments from Battelle researchers’ under 

he regulatory work of Midwest Regional Carbon Sequestration Partnership’s 

(MRCSP) on the USEPA Proposed Rule- Federal Requirements under UIC Program for 

CO2 Geologic Sequestration Wells (Docket ID No. EPA-HQ-OW2008-390). These 

comments reflect our experience in permitting and implementing three Phase II 

CO2 injection tests and the MRCSP Phase III project, as well as work on several 

other research projects during last 12 years of CCS research at Battelle: 

Table [see PDF Docket ID EPA-HQ-OW-2008-390-0229.1] 

The analysis also reflects Battelle experience with the UIC permitting of the 

AEP Mountaineer CO2 storage project, which is targeting 4 years of injection of 

over 100,000 metric tons CO2/yr at the AEP Mountaineer plant in New Haven, WV. 

While the MRCSP includes over 30 different members, the comments expressed 

herein do not necessarily reflect opinions of the individual members of the 

MRCSP. 

The MRCSP is one of seven partnerships in a nationwide effort to determine 

regionally-appropriate carbon sequestration options and opportunities. These 

partnerships are part of an overall effort by the U.S. Department of Energy’s 

37
National Energy Technology Laboratory (DOE/NETL) to develop robust strategies 

for mitigating carbon dioxide emissions. The MRCSP was formed to assess the 

technical potential, economic viability, and public acceptability of carbon 

sequestration within its Region. 

The MRCSP region consists of eight contiguous states: Indiana, Kentucky, 

Maryland, Michigan, New York, Ohio, Pennsylvania, and West Virginia. The MRCSP 

includes over 30 organizations from the research community, energy industry, 

universities, non-government, and government organizations. In the first phase 

of research, which took place over a two year period ending in September 2005, 

the MRCSP characterized carbon sequestration opportunities in the region. MRCSP 

is now involved in a four year Phase II effort that began in October 2005. This 

phase will conduct several small-scale field tests of sequestration in different 

locations around the region to evaluate various sequestration options in realworld settings. The MRCSP Phase III project will involve sequestration of more 

than 1 million metric tons CO2. 

Response: EPA acknowledges the value of the DOE pilot projects and resultant data and

information generated by such projects. EPA has evaluated permits and reviewed operational data

and information associated with the seven RCSPs funded by the U.S. Department of Energy and

coordinated through the National Energy Technology Laboratory (NETL). 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. The Agency will

continue to track GS project developments and evaluate new and ongoing research and information

to ensure USDW protection, including those performed by the MRCSP.

EPA is using an adaptive approach to regulating GS under the UIC Program. Even after finalizing

the rule, the Agency plans to collect and review data every six years on GS projects, including data

generated by the partnerships, to determine whether the appropriate amount and types of information

and appropriate documentation are being collected, and to determine if modifications to the

requirements are appropriate or necessary.

Commenter Name: Craig Hart Letter ID: 0261

Commenter Organization: Alston & Bird LLP Comment ID: 22981

Comment: These comments concern the application of the proposed rule to CO2 injections 

for research and test purposes, and are based on a study I recently completed 

of the Phase II test injections of the U.S. Department of Energy Regional Carbon 

Sequestration Partnerships Program (RCSP): C. Hart, Advancing Carbon Capture & 

Sequestration Research in an Uncertain Legal and Regulatory Environment: A Study 

of Phase II of the DOE Regional Carbon Sequestration Partnerships Pilot Projects 

(Energy Technology Innovation Program, John F. Kennedy School of Government, 

Harvard University, 2008). 

Response: EPA believes that the GS regulation will provide certainty to industry and the public

about requirements that apply to injection, by providing consistency in requirements across the

United States and transparency about what requirements apply to owners or operators.

38
EPA acknowledges the value of the DOE pilot projects and resultant data and information generated

by such projects. EPA has evaluated permits and reviewed operational data and information

associated with the seven RCSPs funded by the U.S. Department of Energy and coordinated through

the National Energy Technology Laboratory (NETL). 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. The Agency will continue

to track GS project developments and evaluate new and ongoing research and information to ensure

USDW protection.

EPA is using an adaptive approach to regulating GS under the UIC Program. Even after finalizing

the rule, the Agency plans to collect and review data every six years on GS projects, including data

generated by the partnerships, to determine whether the appropriate amount and types of information

and appropriate documentation are being collected, and to determine if modifications to the

requirements are appropriate or necessary.

Commenter Name: Craig Hart Letter ID: 0261

Commenter Organization: Alston & Bird LLP Comment ID: 22989

Other EPA Comment Codes and Descriptions: 4710 2.7.1 Proposed submissions required for

permit applications (seeking comment) 

Comment: As EPA considers its proposed rule for Class VI wells under the SDWA UIC 

program, we will have additional information about the CCS permitting process 

from the DOE RCSP Phases II and III projects. As part of its review of the 

proposed rules for Class VI injection wells, EPA should take account of this 

experience and consider providing an improved permitting regime for small-scale 

research projects in order to facilitate CCS research and development efforts. 

Response: The final rule allows owners or operators to continue using the Class V experimental well

permit process for small-scale projects that are experimental in nature. EPA believes that the Class V

and Class VI permitting requirements are necessary to protect USDWs from endangerment, and are

based on site-specific and project-specific information, including CO2 volume. EPA believes that

the requirements for GS owners or operators are flexible enough to take into account plant operating

data, including the volume to be injected.

The Agency is also tracking operation and technical developments of more than three dozen smalland large-scale GS injection projects in the United States and abroad. EPA meets regularly with

DOE to discuss its research initiatives, project developments, and "best practices." 

EPA is using an adaptive approach to regulating GS under the UIC Program. Even after finalizing

the rule, the Agency plans to collect and review data every six years on GS projects, including data

generated by the partnerships, 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.

As described above, EPA disagrees with the suggestion that it should streamline the approval process

for small-volume operators. EPA believes that the information required to be submitted with the

permit application under §146.82 is necessary and appropriate to provide permitting authorities

sufficient information on which to base informed decisions about establishing permit conditions and

39
granting permits. The purpose of these requirements is to protect USDWs from endangerment, and

like large-volume operations, small-volume operations must be permitted and operated in manner

that is protective of USDWs.

Comment Code: 1854 1.4.2.2 Other Pilot Projects 

Individual Comments

Commenter Name: Ellen Gilinsky Letter ID: 0157

Commenter Organization: Virginia Department of Environmental Quality

(DEQ)

Comment ID:

21264

Other EPA Comment Codes and Descriptions: 1510 1.2.2.3 Need for additional study 

Comment: carbon dioxide. The pilot projects will provide additional information to 

strengthen the technical criteria associated with the long-term storage of 

carbon dioxide. DEQ encourages the Environmental Protection Agency to postpone 

adoption of the Class VI regulations until all of the Phase II and Phase III pilot 

projects have been completed. Time taken to organize and thoroughly analyze 

information from these completed pilot projects should ensure final regulations 

that are protective of our natural resources. 

Response: EPA believes that sufficient data and experience currently exist to develop regulations for

GS wells. The GS rulemaking builds upon decades of knowledge about safe injection practices

regulated by the UIC Program. While developing the GS regulation, EPA has evaluated relevant GS

research, including projects conducted by the seven Regional Carbon Sequestration Partnerships

(RCSPs) funded by DOE and coordinated through the National Energy Technology Laboratory

(NETL), and several international projects. 

EPA acknowledges that, because all GS in the United States is currently associated with pilot

projects, there are many unknowns about how GS projects will unfold and the practicalities of

permitting, operating, monitoring, and closing a GS project. Therefore, EPA is using an adaptive

approach to regulating GS. EPA will collect and review project data on early GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are required and being collected and determine if modifications to the requirements are necessary.

EPA agrees that continued research will be integral to the development of GS technology, but

disagrees that the Agency should wait for the DOE pilot studies to be complete before finalizing the

GS rule. EPA believes that establishing a regulatory framework for the future development and

deployment of CCS technology protects USDWs from endangerment and will not impede industry

adoption of CCS. EPA published a Notice of Data Availability and Request for Comment (NODA)

on August 31, 2009 (74 FR 44802), in which the Agency described the results of research at three

DOE partnership sites (in Escatawpa, Mississippi; the Aneth Field in Paradox Basin, southeast Utah;

and the Pump Canyon Site, New Mexico). EPA has used the data generated to inform the final rule

and will continue to monitor ongoing research.

Comment Code: 1858 1.4.2.4 International GS efforts 

40
Individual Comments

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141

Commenter Organization: Global Energy, Inc. Comment ID: 23101

Comment: 2.Your note about the Weyburn EOR project in Saskatchewan Province, Canada is 

valid and highly relevant. Not only has the project demonstrated the commercial 

viability of EOR, but it has also rigorously demonstrated measurable, quantified 

and verified carbon storage. That is, the CO2 is remaining in horizon and is 

conforming to and validating model predictions. 

Response: EPA acknowledges the comment about Weyburn, and agrees that activities there have

relevance for the rule. EPA has monitored progress at the site to gain input and information

regarding GS, and will continue to do so. 

EPA is using an adaptive approach to regulating GS. EPA plans to collect and review project data

every six years on early GS projects to determine whether the appropriate amount and types of

information and appropriate documentation are required and being collected. The Agency will

evaluate the information and determine if modifications to the requirements are necessary.

Comment Code: 1900 1.4.3 Technical workshops 

Individual Comments

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114

Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22534

Comment: EPA at 73 FR 43501, tells the reader of the proposed rule to go to 

http://www.epa.gov/safewater/uic/ so as to read the findings of the various 

Class VI Workshops. Unfortunately, the presentations are, for the most part, 

PowerPoint slideshow without voice over. Thus, the slideshows are difficult to 

interrupt and only contain EPA presented materials. When EPA refers to comments 

and questions from the attendees, EPA provides only an interpretation of the 

questions or comments, thus no context is provided. This places the commenter 

regarding the proposed rule at a severe disadvantage. Reading of the various 

documents available on the website demonstrates no issues of post closure 

monitoring or long term funding for corrective action were raised, or 

discussions recorded. The EPA references to the websites suggest substantive 

discussions occurred during the Workshops. The EPA record demonstrates, little 

or nothing was accomplished during the Workshops. EPA deprives the commenters 

of accurate input from the Workshops. For example, EPA at 73 FR 43520 states: 

Response: EPA clarifies that the workshop PowerPoint slides to which the commenter refers were

presented by EPA. Following the presentations EPA answered questions and these responses are

included in the workshop summaries, which are available in the electronic docket.

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114

41
Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22535

Other EPA Comment Codes and Descriptions: 5400 2.9 Proposed Financial Responsibility and

Long-Term Care Requirements 

Comment: or nothing was accomplished during the Workshops. EPA deprives the commenters 

of accurate input from the Workshops. For example, EPA at 73 FR 43520 states: 

"...SDWA does not have explicit provisions for financial responsibility, as 

included in RCRA, EPA believes that the general authorities provided under the 

SDWA authority to prevent endangerment of USDWs include the authority to set 

standards for financial responsibility to prevent endangerment of USDWs from 

improper plugging, remediation, and management of wells after site closure. The 

SDWA authority does not extend to financial responsibility for activities not 

related to protection of USDWs (e.g., coverage of risks to air, ecosystems, 

public health or public safety unrelated to USDW endangerment). It also does not 

cover transfer of owner or operator financial responsibility to other entities, 

or creation of a third party financial mechanism where EPA is the trustee." 

Response: As described above, the summaries of the workshop discussions were condensed to make

them more readable. EPA notes that it received numerous comments on financial responsibility

during the comment period for the proposed rule. These comments are available in the docket for this

rule.

In reference to comments on financial responsibility, as described above, under SDWA, EPA has the

general authority to set financial responsibility requirements for injection well owners or operators to

ensure that adequate resources are available to protect USDWs throughout the life of the GS project.

However, this authority does not extend to allowing the Agency to create a financial instrument with

EPA as the trustee, due to the restrictions of the Miscellaneous Receipts Act (MRA). The MRA

requires that EPA deposit the funds it receives for the use of the Government into the Treasury,

therefore funds would not necessarily be available for GS financial responsibility. 

The Agency clarifies that the trust funds that are addressed as financial responsibility instruments on

the GS rule are set up by individual owners or operators and are different from a national-level trust

described by the commenters that would cover large numbers of GS projects. See the final rule and

preamble for further discussion of EPA's final approach to financial responsibility.

Comment Code: 1910 1.4.4 Stakeholder outreach 

Individual Comments

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114

Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22539

Comment: ADAPTIVE APPROACH 

EPA, at 73 FR 43522, requests input regarding using electronic means of 

involving the public in the rule making process. From our vantage point of 

reading the Federal Register daily, the use of the web is highly satisfactory. 

However, we find most citizens don’t know the Federal Register exists. Thus, 

42
the public does not have any idea what regulations are being proposed or 

promulgated. EPA needs to be out-going with their information, e.g., put 

notices in the newspapers, sponsor television Public Notices, etc. Currently, 

the public is uninformed and will remain uninformed, if the Agency relies solely 

on the Federal Register.! 

Response: EPA clarifies that it asked for comment on the use of electronic media to inform

stakeholders of the availability of individual Class VI permit applications, not on the use of

electronic media to inform the public about regulations themselves. However, EPA clarifies that it

notifies interested stakeholders when it proposes and finalizes new rules. EPA also posts information

about current and recent rulemakings on its website http://www.epa.gov/safewater. In addition, EPA

issues press releases on its regulatory actions, and the news media often write articles about EPA

proposed and final rules.

Commenter Name: Anonymous2 Letter

ID: 0133

Commenter Organization: Sierra Club National Global Warming and Energy

Committee and Sierra Club California-Nevada Regional Conservation Committee on

Energy and Climate Change

Comment

ID: 21614

Comment: While the more difficult legal entanglements will require federal legislation 

and/or federal adjudication, an optimal structure for administering regionallytailored regulations would include a specialized administrator and staff to 

coordinate and direct all CCS-related projects within each of the EPA's 10 

regions, supported by an independent Board of Advisors with members who reside 

in each of those regions. To fulfill guidelines established at 40 CFR 25.7, the 

Board would be comprised of balanced representatives from groups of major 

stakeholders, such as: municipal and state government officials, EOR/EGR 

companies, CCS project managers, electric utility companies, public and 

municipal water providers, renewable energy providers, environmental groups, 

community members, research scientists, geologists, public policy consultants. 

This administrative structure would facilitate the protection of states' 

divergent local needs while maintaining an umbrella of national standards for 

the regulation of complex methodologies. 

In order for public acceptance to remain high -- as more fully discussed in the 

third section -- it is necessary for the Board to consistently and carefully 

maintain a balanced representational roster. A case in point is the current 

composition of the Ground Water Protection Council, through which the EPA 

interacts and "shares information and collaborates with [state UIC] primacy 

programs"(http://www.epa.gov/safewater/uic/primacy.html). The GWPC's web site 

states that it is comprised of academicians, citizens, environmentalists, 

government officials, and industry representatives. However, its current roster 

of principals is almost exclusively comprised of government officials, 

government consultants, fossil fuel industry representatives, and fossil fuel 

industry consultants. It is virtually lacking in representative academicians, 

citizens, environmentalists, public interest professionals, or public policy 

consultants. It is imperative that the composition of the Regional Advisory 

Boards be truly representative of local citizens and non-partisan technical 

consultants so that communities can participate in Class VI permitting processes 

and facilitate acceptance of geosequestration projects in their regions. 

43
Response: EPA will continue to consult with a variety of stakeholders, including the National

Drinking Water Advisory Council, associations and organizations, ORD, and experts; review

permits; and continue to hold workshops to build expertise and ensure that implementation of the

national program is based on the best available science. 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.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23383

Comment: We thank EPA for the regional workshops and public hearings associated with this 

proposed rule, the willingness of staff to meet with our electric (and water) 

utility representatives, and for the openness in the meetings about the tough 

issues inherently involved with drinking water protection with an entirely new 

technology (given the scale) for the power plants sector. 

Response: EPA acknowledges the comment and agrees that input of and participation by a wide

spectrum of stakeholders is a vital component of successful rulemaking. The Agency appreciates the

degree of cooperation, participation, and active dialogue between the EPA and stakeholders and will

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

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23675

Other EPA Comment Codes and Descriptions: 5560 2.10.3 Enhancing the public participation

process (seeking comment) 

Comment: Data and Research Needs: AWWA believes that stakeholder access to the necessary 

data is lacking and will inhibit making informed/transparent decisions on 

geologic carbon sequestration projects. Stakeholders need better and more 

accessible data and data reduction tools (i.e., GIS maps). EPA should consider 

creating an interactive web based data warehouse that would store data and GIS 

layers on large carbon dioxide emitters, drinking water groundwater basins, 

seismic/volcanic/geothermal zones, proposed carbon dioxide saline injection 

basins, etc. and provide the ability to overlay layers. Stakeholders would then 

have improved abilities to evaluate a proposed geologic sequestration project to 

determine if they would be impacted by the carbon dioxide plume and/or 

associated pressure front. 

Response: EPA notes that the full results of the regional carbon sequestration partnership pilot

projects will be available to the public once the projects are complete (the results of Phase II of these

projects are currently available). Results of other research sponsored by EPA and DOE are available

in the GS rulemaking docket as it is complete. 

EPA agrees that all information presented to the public must be clear, understandable, and available.

In addition to requiring public notice of all draft permits under §124.10(a)(1)(ii), stakeholders may

request copies of the draft permit and the permit application during the draft permit comment period;

the application includes data on the geology of the injection and confining zones which are likely to

be used as inputs for modeling. However, it is likely that information submitted in support of a

44
permit in its original form (e.g., modeling inputs) may be extremely technical and not easily

understood by a lay audience. Permitting authorities are required under §124.8 to produce a fact

sheet which typically summarizes relevant information for the public in a much more understandable

format than the supporting data in a permit application. The fact sheet describes the draft permit

conditions, procedures to determine the final decision on the permit, any procedures to request a

hearing, and procedures that may be available for additional public participation in the final

permitting decision. EPA will encourage permitting authorities and operators to present all modeling

data to the public. 

EPA has no plans to create a web-based GIS database, due to the sheer volume of information

required and variety in GIS software products available by potential users. 

Information about specific GS projects would be available from permitting authorities as part of the

administrative record associated with each permit. EPA will encourage (but not require) that this

information be available online. 

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21700

Comment: As EPA develops revisions or potential modifications to financial assurance 

guidance that would be applied to UIC permits, it should provide further public 

notice, review and engagement opportunities that allow for feedback to EPA on 

specific proposals. 

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

comment before finalizing the rule. In addition, EPA is using an adaptive approach to regulating GS

under the UIC Program. Even after finalization of the GS regulation, the Agency plans to collect and

review 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.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21711

Comment: As an initial matter, we applaud EPA’s significant efforts to include and 

encourage broad stakeholder participation both before and after publication of 

the Proposed Rule. Furthermore, it is evident from the Proposed Rule that EPA 

considered and incorporated many of the stakeholders’ comments from the public 

workshops. Accordingly, EPA adopted a framework that is intended to encourage 

Response: EPA acknowledges the comment and agrees that input of and participation by a wide

spectrum of stakeholders is a vital component of successful rulemaking. The Agency appreciates the

degree of cooperation, participation, and active dialogue between the EPA and stakeholders and will

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

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21757

Comment: As EPA develops revisions or potential modifications to financial assurance 

guidance that would be applied to UIC permits, it should provide further public 

notice, review and engagement opportunities that allow for feedback to EPA on 

45
specific proposals. 

Response: EPA subjected the financial responsibility guidance to expert review; the final guidance

reflects this input. In addition, EPA is using an adaptive approach to regulating GS under the UIC

Program. Even after finalization of the GS regulation, the Agency plans to collect and review 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. EPA will also evaluate whether any changes to the GS

rule necessitate revisions to the guidance.

Comment Code: 1930 1.4.4.2 Consultations with State, Tribal, and local Associations (e.g., GWPC,

IOGCC) 

Individual Comments

Commenter Name: Sam Kitto Letter ID: 0126

Commenter Organization: National Tribal Air Association Comment ID: 23048

Other EPA Comment Codes and Descriptions: 1600 1.3 Risk Associated with CO2 GS 

Comment: As will be noted further in our comments, the EPA failed to adequately consult 

with Indian tribes on the GS rule. If the Agency had properly consulted, many 

tribes might have communicated that the lands on which they live are highly 

diverse and environmentally sensitive. As such, geologic sequestration conducted 

on or near these lands requires extra due diligence to ensure the safety of 

tribes and their environments. Every effort to mitigate the environmental 

impacts of geologic sequestration, even beyond impacts to USDWs, must be taken 

by the EPA. 

The NTAA therefore recommends that the EPA provide specifics on how it will help 

protect Indian tribes and their lands from the environmental impacts of geologic 

sequestration, even impacts beyond those to USDWs. 

Response: EPA clarifies that regulating environmental impacts beyond impacts of endangerment to

USDWs is beyond the scope of EPA’s authority under the Safe Drinking Water Act and outside the

scope of this rulemaking. However, EPA believes that the GS rule, properly implemented, will

protect USDWs and the overlying land from endangerment.

Throughout the GS rulemaking, EPA has promoted a transparent stakeholder process to ensure that

all stakeholders understood the rulemaking elements and that viewpoints and suggestions for rule

modifications were recorded. EPA, with support from the American Indian Environmental Office

(AIEO), engaged and consulted Tribes early in the rulemaking process, and continued to update

Tribal representatives as appropriate. Additionally, the Agency provided tribes with the contact

information for EPA managers in order to facilitate communication throughout the rulemaking

process. 

In April 2008, prior to publication of the proposed GS rule, the Agency sent background information

about the proposed rulemaking to all federally recognized American Indian tribes. In addition, EPA

communicated with the National Tribal Caucus of the National Operations Committee (NTC) and

46
the National Tribal Water Council (NTWC) to encourage participation in a dedicated consultation on

the rulemaking. On April 24, 2008, the Agency held a conference call with all interested tribal

representatives; a summary is included in the rulemaking docket. Additionally, an EPA

representative presented information on GS and the GS regulatory framework at the National Tribal

Council on Environmental Management (NTCEM) Meeting in Billings, Montana, in June 2008. In

September 2008, during the proposed rule public comment period, EPA held two public hearings at

which tribes were represented. 

Throughout 2009 and 2010, more recent updates on the GS rulemaking were presented to tribal

representatives through regularly scheduled calls with the NTWC, State and Tribal Climate Change

Council (STC3), and the National Tribal Caucus. Representatives had the opportunity to ask EPA

managers questions related to the rulemaking elements and finalization schedule. EPA believes that

all of the actions undertaken were conducted to support an open and transparent rulemaking process

in accordance with Executive Order 13175 and Agency recommendations. 

EPA clarifies that following publication of the proposed rule in July 2008, the Fort Peck Assiniboine

and Sioux Tribes and the Navajo Nation received UIC Program primacy for the Class II program

under §1425 of the SDWA. EPA recognizes those tribes as co-regulators and remains committed to

ensuring that co-regulators are informed on and have an opportunity to engage with EPA on the GS

rule. To further ensure coordination and communication regarding the GS rule, EPA hosted a

conference call specifically for the Fort Peck Assiniboine and Sioux Tribes, as well as the Navajo

Nation, UIC Program Directors in February 2010. EPA representatives presented the history of the

rulemaking, the current schedule for finalization of the rule, and the statutory differences in applying

for primacy for the proposed Class VI program versus applying for primacy for the Class II program.

A summary of the call is included in the docket for the GS rulemaking.

The Agency is currently reviewing its tribal consultation policies and procedures in accordance with

the President's directive of November 5, 2009. When that review is final, there will be more

clarification from EPA on tribal consultation during program implementation.

In response to the comment that "extra due diligence" should be required on Tribal lands, EPA

clarifies that the Class VI GS rule requirements are protective and apply to all USDWs. EPA clarifies

that States, Tribes, and Territories that seek primacy for the Class VI program may adopt

requirements that are more stringent than the minimum federal requirements in the GS rule.

Commenter Name: Sam Kitto Letter ID: 0126

Commenter Organization: National Tribal Air Association Comment ID: 23049

Comment: Consultation 

With respect to consultation, the EPA failed to conduct what the NTAA would 

consider to be meaningful consultation between the Agency and the nation’s 

tribes, failing among other things, to develop and follow an appropriate tribal 

consultation plan. 

Response: EPA disagrees with the commenter's assertion. EPA’s tribal consultations during the

development of the GS rule are described in the response above.

Commenter Name: Sam Kitto Letter ID: 0126

Commenter Organization: National Tribal Air Association Comment ID: 23050

47
Other EPA Comment Codes and Descriptions: 7600 4.6 Executive Order 13175: Tribal

Consultation and Coordination 

Comment: According to the EPA, the GS rule does not have tribal implications as accorded 

by Executive Order 13175, largely because Indian tribes do not have primacy over 

an underground injection control (UIC) program (the Fort Peck Assiniboine and 

Sioux Tribes, and the Navajo Nation have received primacy since publication of 

the GS rule). This is a faulty rationale as Indian tribes could be placed in 

harm’s way as a result of geologic sequestration occurring on or near their 

lands. As already noted above, geologic sequestration could have significant 

environmental impacts on tribes, but their cultural practices could be affected 

as well. For example, a number of tribes depend upon certain plants for cultural 

and religious ceremonies, and with increased soil acidity due to CO2 leakage 

from geologic sequestration, the health and survival of these plants could be in 

jeopardy. 

Although admitting that the GS rule will not impact tribes, the EPA claims that 

it did in fact consult with Indian tribes. What the NTAA can gather from the 

rule, however, is that the Agency simply contacted tribes about engaging in the 

rulemaking process and held one conference call; the EPA has also promised to 

"continue an ongoing dialogue with interested tribes on this rulemaking." This 

approach taken by the Agency falls far short of what a true government-togovernment consultation between the federal government and tribes should look 

like. As inferred above, a tribal consultation plan could have helped overcome 

any concerns about Indian tribes not being properly consulted by the EPA with 

respect to the GS rule. The NTAA believes, however, that an opportunity for 

developing such a plan still exists, but requires at a minimum that the comment 

rule concerning the GS rule be extended no less than 90 days; the NTAA also 

gladly offers its resources to help develop such a plan. 

Response: Throughout the GS rulemaking, EPA has promoted a transparent stakeholder process to

ensure that all stakeholders understood the rulemaking elements and that viewpoints and suggestions

for rule modifications were recorded. EPA, with support from the American Indian Environmental

Office (AIEO), engaged Tribes early in the rulemaking process, and continued to update Tribal

representatives as appropriate. Additionally, the Agency provided tribes with the contact information

for EPA managers in order to facilitate ongoing communication throughout the rulemaking process. 

In April 2008, prior to publication of the proposed GS rule, the Agency sent background information

about the proposed rulemaking to all federally-recognized American Indian tribes. In addition, EPA

communicated with the National Tribal Caucus of the National Operations Committee (NTC) and

the National Tribal Water Council (NTWC) to encourage participation in a dedicated consultation on

the rulemaking. On April 24, 2008, the Agency held the conference call with all interested tribal

representatives. A summary of the call is included in the rulemaking docket. Additionally, an EPA

representative presented information on GS and the GS regulatory framework at the National Tribal

Council on Environmental Management (NTCEM) Meeting in Billings, Montana, in June 2008. In

September 2008, during the proposed rule public comment period, EPA held two public hearings at

which tribes were represented. 

Throughout 2009 and 2010, more recent updates on the GS rulemaking were presented to tribal

representatives through regularly scheduled calls with the NTWC, State and Tribal Climate Change

Council (STC3), and the National Tribal Caucus. Representatives had the opportunity to ask EPA

48
managers questions related to the rulemaking elements and finalization schedule. EPA believes that

all of the actions undertaken were conducted to support an open and transparent rulemaking process

in accordance with Executive Order 13175 and Agency recommendations. 

EPA clarifies that following publication of the proposed rule in July of 2008, the Fort Peck

Assiniboine and Sioux Tribes and the Navajo Nation received UIC Program primacy for the Class II

program (under 1425 of the SDWA). EPA recognizes those tribes as co-regulators and remains

committed to ensuring that co-regulators are informed on and have an opportunity to engage with

EPA on the GS rule. To further ensure coordination and communication regarding the GS rule, EPA

hosted a conference call specifically for the Fort Peck Assiniboine and Sioux Tribes, as well as the

Navajo Nation, UIC Program Directors in February 2010. EPA representatives presented the history

of the rulemaking, the current schedule for finalization of the rule, and the statutory differences in

applying for primacy for the proposed Class VI program versus applying for primacy for the Class II

program. EPA received comments from the Navajo Nation UIC Director as a co-regulator for the

program. A summary of the call is included in the docket for the GS rulemaking.

In response to the concern raised that tribes could be adversely affected by Class VI well projects

because they may be sited on or near Indian country, EPA clarifies that the Federal UIC regulations

are designed to ensure protection of USDWs from endangerment associated with injection activities.

These regulations protect all populations from adverse health effects associated with endangerment

to USDWs. EPA clarifies that regulating environmental impacts beyond impacts of endangerment to

USDWs is beyond the scope of EPA’s authority under the Safe Drinking Water Act and this

rulemaking. 

The Agency is currently reviewing its tribal consultation policies and procedures in accordance with

the President's directive of November 5, 2009. When that review is final, there will be more

clarification from EPA on tribal consultation during program implementation. 

Commenter Name: Richard Guinn Letter ID: 0210

Commenter Organization: Eastman Chemical Company Comment ID: 22700

Comment: 9. EPA should increase its state stakeholder effort towards uniformity of 

technical requirements; disparate requirements and processes will increase the 

time, cost, and complexity of projects. 

Response: EPA will continue to consult with a variety of stakeholders, including the National

Drinking Water Advisory Council, associations and organizations, ORD, and experts; review

permits; and continue to hold workshops to build expertise and ensure that that implementation of

the national program is based on the best available science. 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.

The GS rule provides flexibility to determine the suitability of a proposed site based on extensive,

site-specific data. EPA believes that requiring appropriate site characterization by the owner or

operator and providing an appropriate degree of flexibility to the Director to evaluate site-specific

geologic data will afford the greatest protection of USDWs. The issuance of a UIC Class VI permit

is determined based on evaluation of site-specific permit information pursuant to the requirements at

§§146.82 and 146.83.

49
Commenter Name: Abbie Krebsbach Letter ID: 0235

Commenter Organization: Montana-Dakota Utilities Co. Comment ID: 23193

Other EPA Comment Codes and Descriptions: 1250 1.1.1.4 Flexibility is needed (performancebased standards) 

Comment: Limits on EPA Authority and Discretion 

EPA should consider the significant interests and experience of the states in 

developing regulations. Montana-Dakota recognizes that in order to allow for 

effective site-specific determinations and to maintain essential regulatory 

flexibility, some amount of discretion must be vested in the UIC program 

director. At the same time, such discretion should be bounded by the inclusion 

of relevant and appropriate considerations for making necessary determinations. 

In general, the rules should establish with sufficient clarity the factors to be 

taken into account and leave the precise determinations to the permit process. 

Response: The GS rule provides flexibility to determine the suitability of a proposed site based on

extensive, site-specific data. EPA believes that requiring appropriate site characterization by the

owner or operator and providing an appropriate degree of flexibility to the Director to evaluate sitespecific geologic data will afford the greatest protection of USDWs. The issuance of a UIC Class VI

permit is determined based on evaluation of site-specific permit information pursuant to the

requirements at §§146.82 and 146.83.

EPA is developing guidance materials that describe the process of applying for and receiving

primary enforcement responsibility (primacy) for GS Class VI wells under Section 1422 of SDWA,

as well as the technical and administrative issues on developing GS regulations that are the

equivalent of minimum federal criteria and requirements. This guidance and training addresses areas

where the Director is given discretion in implementing the requirements. Such requirements where

the Director has discretion include: whether to require owners or operators to identify and

characterize additional confining zones under §146.83, whether to require surface air monitoring

and/or soil gas monitoring under §146.90, and whether to extend or shorten the post-injection site

care period or approve an alternative post-injection site care timeframe as part of the permitting

process under §146.93

Commenter Name: Kevin Frederick Letter ID: 0525

Commenter Organization: Wyoming Department of Environmental Quality Comment ID: 21395

Comment: Lastly, U.S. EPA should seriously review and consider the comments that will be 

provided in the future in this proposed rule by the Ground Water Protection 

Council. The Ground Water Protection Council has a working committee comprised 

of members from industry, state regulatory agencies, and environmental interest 

groups that are reviewing the proposed rule and we believe we will be providing 

important comments that EPA should consider in reviewing the proposed rule. 

Response: EPA reviewed GWPC’s comments on the proposed rule; EPA’s response can be found in

the docket for this rule.

Commenter Name: Paul Pike Letter ID: 0535

Commenter Organization: Ameren Corporation on behalf of Utility Solid Waste Comment ID:

50
Activities Group (USWAG) 21438

Other EPA Comment Codes and Descriptions: 1540 1.2.3.2 Climate change legislation 

Comment: USWAG recognizes that while there are some measures Agency can take in the 

regulatory context to address these concerns, those measures may be limited. In 

the end USWAG also believes that the Agency should consider whether legislative 

solutions will be necessary and if so, we strongly support that they take such 

action. Because state regulators have worked extensively with permitting the 

existing injection wells, we believe that we should work with those agencies to 

continue and to have implementation of the Class VI rules by the states would be 

crucial to the UIC program. 

Response: EPA agrees that states should implement the Class VI rule. EPA believes that allowing

states to obtain Class VI primacy may encourage them to take responsibility for implementation of

Class VI regulations and provide for a more comprehensive approach to managing CCS projects by

promoting the integration of GS activities under SDWA into a broader framework for managing

CCS. Furthermore, GS operations involve ancillary activities (e.g., pipeline operations, pore space

ownership, land use rights, and surface access) for which states can call upon other authorities that

exist at the state level but are outside UIC authority to provide a more comprehensive CCS

management approach. EPA acknowledges that some states and tribes are developing statutory

frameworks, regulations, technical guidance, and strategies for addressing broader issues related to

CCS and GS, and encourages states to seek primacy for Class VI wells to further these efforts.

EPA 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. EPA clarifies that the scope of this GS

regulation is limited to underground injection of CO2, and that all requirements in the GS rule are

designed to ensure protect USDWs from endangerment.

EPA acknowledges that GS falls within the broader context of CCS and the need for regulatory

clarity to ensure that USDWs are protected from endangerment. In developing the final GS rule, the

Office of Water coordinated with other Agency program offices and across federal agencies (e.g.,

with the Department of Energy; United States Geological Survey; Bureau of Ocean Energy

Management, Regulation, and Enforcement, formerly the Minerals Management Service; Bureau of

Land Management). The Agency continues to evaluate areas of potential applicability of other

Federal environmental statutes including, but not limited to: the Clean Air Act; the Resource

Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, and

Liability Act; and the Marine Protection, Research and Sanctuaries Act to various aspects of GS and

CCS. The Agency will continue to coordinate on GS and CCS related issues to minimize redundancy

and maximize efficiencies for owners or operators. For additional information, please see the

discussion entitled "How Does This Rulemaking Relate to Other Federal Authorities and GS and

CCS Activities?" in the preamble to the final GS rule. 

Comment Code: 1940 1.4.4.3 Consultations with Industry; experience with other wells 

Individual Comments

Commenter Name: Brian Williams Letter ID: 0116

51
Commenter Organization: BP Alternative Energy Comment ID: 22049

Other EPA Comment Codes and Descriptions: 1320 1.1.3 General comments about GS 

Comment: EPA has correctly recognized that wells are a fundamental component of a 

geologic storage system that successfully ensures the containment of stored CO2. 

As such, we agree that having appropriate well design, construction & operating 

requirements are critical to the delivery of secure storage of CO2. 

Oil and gas operators have decades of experience, via past and existing 

operations, in constructing and operating EOR/EGR wells in a safe and secure 

way. For existing EOR projects and wells, Class II requirements have proven to 

be sufficient at ensuring the necessary protection of USDWs, and, therefore, 

analysis of the experiences and performances of these Class II CO2 EOR wells 

should inform the requirements for new Class VI wells. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. Some of the research that informs the final GS rule was conducted at ER sites. EPA also

recognizes that a by-product of ER activities is that a certain percentage of the CO2 is trapped in the

receiving formation.

In addition, EPA is using an adaptive approach to regulating GS under the UIC Program. Even after

finalization of the GS regulation, the Agency plans to collect and review 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. 

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141

Commenter Organization: Global Energy, Inc. Comment ID: 23098

Comment: 3.Global supports EPA’s view that the oil and gas industries have experience 

that can inform and facilitate pragmatic implementation of this rule. 

Activities to support siting, and well installation, are readily accomplished 

and are common to those industries. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. EPA also recognizes that a by-product of ER activities is that a certain percentage of the CO2

is trapped in the receiving formation.

Also, since field experience and well construction, injection, and monitoring information relevant to

GS comes from operations that inject acid gas or inject CO2 for ER, the Agency has conducted

evaluations regarding these commercial field operations and continues to track GS-relevant

developments in these commercial operations. Some of the research that informs the final GS rule

was conducted at ER sites.

Commenter Name: Abbie Krebsbach Letter ID: 0235

Commenter Organization: Montana-Dakota Utilities Co. Comment ID: 23195

Comment: Much of the experience and expertise associated with injection and storage of 

52
CO2 that currently exists is the result of several decades of experience with 

EOR and enhanced gas recovery operations through Class II UIC permits. As CCS 

gains momentum as a GHG mitigation tool, EOR operators may provide not only this 

wealth of experience and expertise, but also the first push toward commercial 

CCS by seeking to convert existing EOR operations to purely storage operations 

to take advantage of whatever credits may eventually become available under 

climate change legislation or regulation. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. EPA also recognizes that a by-product of ER activities is that a certain percentage of the CO2

is trapped in the receiving formation. Some of the research that informs the final GS rule was

conducted at ER sites. 

EPA clarifies that comments related to climate change legislation or regulations are outside the

scope of the GS rulemaking.

Commenter Name: William Herz Letter ID: 0266

Commenter Organization: The Fertilizer Institute Comment ID: 22884

Comment: TFI has been pleased to submit these comments on EPA's NPRM. TFI thanks EPA for 

advancing an important tool for future carbon sequestration with the Agency's 

proposed requirements under the SDWA for underground injection of CO2 for the 

purpose of GS. We urge EPA to work with potential industrial clients to clarify 

the analysis, monitoring and record keeping requirements that will be necessary 

to minimize potential future liability in an effort to promote and facilitate 

implementation of this important carbon emissions mitigation technology 

among industry. Please contact me by telephone at (202) 515-2706 or via e-mail at 

Response: EPA acknowledges the comment and agrees that input of and participation by a wide

spectrum of stakeholders is a vital component of successful rulemaking. The Agency appreciates the

degree of cooperation, participation, and active dialogue between EPA and stakeholders and will

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

several guidance manuals that will help owners and operators comply with the rule.

Commenter Name: Bill Hertz Letter ID: 0500

Commenter Organization: Fertilizer Institute Comment ID: 21214

Comment: We would like to thank EPA for advancing this important tool for future carbon 

sequestration, and urge EPA to work closely with the nitrogen fertilizer 

industry and TFI on the issues that we have raised. And we would like to meet at 

a future convenient date to discuss these issues further. Thank you. 

Response: EPA acknowledges the comment and agrees that input from stakeholders is a vital

component of successful rulemaking, as discussed above.

Commenter Name: Michele Schoepper Letter ID: 0503

Commenter Organization: American Petroleum Institute Comment ID: 21171

Comment: As an industry we have over 35 years of experience safely transporting and 

injecting CO2 for enhanced oil recovery, EOR, while constantly evolving new 

53
technology, operating experience, and regulatory requirements that had been 

developed EOR our extensive, mature, and generally appropriate for CCS. 

In the U.S. alone the oil and gas industry operates over 13,000 CO2 EOR Wells, 

over 3,500 miles of high pressure CO2 pipelines, and has injected over 600 

million tons of CO2 for EOR alone. All while maintaining an excellent health 

environment and safety record. 

Industry also has extensive experience in large scale separation and reinjection of natural gas streams. The largest operation of this kind is on the 

north slope of Alaska where 47 TCF and natural gas consisting of about 12 

percent carbon dioxide has been cumulatively re-injected over the past 30 plus 

years. The CO2 fraction corresponds to approximately 420 million metric tons of 

CO2. 

Response: EPA acknowledges the comment and recognizes that the oil and gas industry has decades

of experience injecting CO2 for the purpose of ER, and that sites used for ER may be suitable for

GS and may be among the first GS sites. Some of the research that informs the final GS rule was

conducted at ER sites. EPA also recognizes that a by-product of ER activities is that a certain

percentage of the CO2 is trapped in the receiving formation.

Commenter Name: Brian Williams Letter ID: 0507

Commenter Organization: BP Alternative Energy Comment ID: 21163

Comment: First, with regard to the recognition of the criticality of wells, our view that 

EPA has correctly recognized that wells are a fundamental component of 

geological storage systems to successfully ensure the containment of stored CO2. 

As such, we agree that having appropriate well design, construction, and 

operating expectations are critical to delivery of secure storage for CO2. 

Oil and gas operators have decades of experience either past and existing 

operations in construction and operating DOR and actual recovery and EGR, that's 

gas recovery wells in a safe and secure way. 

For existing EOR projects and wells Class II requirements have proven to be 

sufficient at ensuring the necessary protection of USDWs, and therefore, 

analysis of the experiences and performances of these Class II Wells, these 

Class II CO2 Wells should inform the specifications for a new Class VI Well. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. EPA also recognizes that a by-product of ER activities is that a certain percentage of the CO2

is trapped in the receiving formation.

EPA believes that GS is sufficiently distinct from Class II ER operations to warrant the tailored

requirements in the 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

54
GS project.

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.

Commenter Name: Steve Crookshank Letter ID: 0523

Commenter Organization: American Petroleum Institute (API) Comment ID: 21354

Comment: As an industry, we have over thirty-five years experience safely transporting 

and injecting CO2 for enhanced oil recovery. While constantly evolving, the 

technology, upgrading practices and regulatory requirements have been developed 

for enhanced oil recovery are extensive, mature and generally appropriate for 

CCS. 

In U.S. alone, the oil and gas industry operates over thirteen thousand CO2 EOR 

wells, over thirty five hundred miles of high pressure CO2 pipelines and has 

injected over six hundred million tons of CO2 for EOR alone all while 

maintaining an excellent health environment and safety record. 

Industry also has extensive experience in large scale separation and reinjection of natural gas streams. The largest operation of this kind is on the 

north slope of Alaska where forty-seven trillion cubic feet of natural gas 

consisting of about twelve percent carbon dioxide has been cumulatively reinjected over the past thirty plus years. The CO2 fraction corresponds to 

approximately four hundred and twenty million metric tons of CO2. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. Some of the research that informs the final GS rule was conducted at ER sites. EPA also

recognizes that a by-product of ER activities is that a certain percentage of the CO2 is trapped in the

receiving formation.

Commenter Name: Dag Nummedal Letter ID: 0533

Commenter Organization: Colorado Energy Resource Institute Comment ID: 21481

Comment: And so I am working very closely with the Norwegian company and other friends 

back in Norway including being a board member on their carbon sequestration 

company called Gas and Nova so again as part of the research we are about to 

undertake, we make sure that all the learnings that are coming out 

55
[indecipherable] also are fully available to all the members of our research 

community. 

Response: EPA acknowledges the comment. While developing the GS regulation, EPA has

evaluated relevant GS research, including projects conducted by the seven Regional Carbon

Sequestration Partnerships (RCSPs) funded by DOE and coordinated through the National Energy

Technology Laboratory (NETL), and several international projects. A paper summarizing EPA's

research on international GS projects and legislation is in the rulemaking docket.

Comment Code: 1960 1.4.4.5 Consultations with NGOs, e.g., environmental and citizens groups 

Individual Comments

Commenter Name: Dag Nummedal Letter ID: 0533

Commenter Organization: Colorado Energy Resource Institute Comment ID: 21480

Other EPA Comment Codes and Descriptions: 1610 1.3.1 Risks to USDWs 

Comment: But according to your point number seven in the handout for today's meeting, 

where you talk about EPA has an upstanding history of working with academic 

community and the national labs to answer basic science questions and I am 

delighted to see that and I know that in fact. I have been dealing with EPA for 

a long time too and I am very pleased that in fact, the labs that you are 

mentioning are mostly the same ones that we believe are the leadership precision 

in this research. You do mention the Lawrence lab. You mention the Pacific 

Northwest labs you are working through, but not formally in this particular 

proposal and you have mentioned little more, but of course [indecipherable] 

strength in the carbon sequestration [indecipherable]. 

Then you mention the regional carbon sequestration partnerships in Colorado is 

member of the southwest partnership headed up by Brian McPherson. Started out in 

New Mexico [indecipherable]. Brian is now at the University of Utah and close 

friend of all of ours. So I have a very close interaction with that partnership 

and also the Big Sky partnership in Montana, in the Great Plains. Now where our 

research already is different and will continue to differ from the partnership 

is that we are not trying to focus on kind of a regional assessment on what 

particular methodology works where which is very much part of the partnership 

and of course, we need that. But instead we want to sit back and look at a much 

more fundamental geomechanical, geomicrobiological and geochemical reactions in 

the subsurface in any kind of rock and we will limit [indecipherable] submitted 

if it gets funded. Get samples and data from these three partnerships that I 

mentioned, so that the research will be tied to the specific environments in the 

Rocky Mountains very likely to store CO2. 

So I think that is -- oh I mentioned the Sleipner project which of course is 

well known. Because Sleipner I attached some CO2 emissions back in 1995 and 

1996. I have mailed it and advantageous for [indecipherable] business 

perspective start sequestering CO2 and I learned a great deal in the process 

about it, so becoming a leader provider on the carbon sequestration expertise 

56
and technology. The and I have been working with Stockholm for a long time as 

you can tell from my accent, I did not grow up in Louisiana, some people think. 

Response: While developing the GS regulation, EPA evaluated relevant GS research, including

projects conducted by the seven regional carbon sequestration partnerships funded by the U.S.

Department of Energy (DOE) and coordinated through the National Energy Technology Laboratory

(NETL), and several international projects, including Sleipner. A paper summarizing EPA's research

on international GS projects and legislation is in the rulemaking docket. Additionally, EPA's Office

of Water continues to fund research at the Lawrence Berkeley National Laboratory examining the

effects of CO2 interaction on ground water aquifers and any potential mobilization of trace elements

that may occur. EPA is communicating with other research organizations and academic institutions

including, among others, Princeton University, Massachusetts Institute of Technology, and Montana

State University, where specific research on geologic sequestration, injection well materials, and

CO2 monitoring techniques is in progress. EPA is also working with DOE, USGS, and others to

identify tools and training techniques that will provide GS permitting assistance and technical

expertise as appropriate. Additionally, EPA's Office of Research and Development (ORD) is

undertaking multiple research efforts on GS. Topics of research include bolstering different default

thermodynamic databases to include more comprehensive information on aqueous complexes and

solid-phases that contain carbonate/bicarbonate and toxic elements for which EPA has a listed MCL

(maximum concentration level) for safe drinking water. 

EPA is using an adaptive approach to regulating GS under the UIC Program. Even after finalization

of the GS regulation, the Agency will, every six years, collect and review data on GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

EPA agrees that research into GS is important and confirms that, as the commenter notes, the final

GS rule was informed by research at LBNL, Pacific Northwest laboratories, the RCSPs, and

international GS research. EPA continues to fund research on GS. As part of its adaptive rulemaking

approach, EPA will continue to review available research on fluid movement. The Agency plans,

every six years, to collect and review data on GS projects to determine whether the appropriate

amount and types of information and appropriate documentation are being collected, and to

determine if modifications to the requirements are appropriate or necessary.

Comment Code: 1970 1.4.4.6 Need for other consultations 

Individual Comments

Commenter Name: Anonymous2 Letter

ID: 0133

Commenter Organization: Sierra Club National Global Warming and Energy

Committee and Sierra Club California-Nevada Regional Conservation Committee on

Energy and Climate Change

Comment

ID: 21581

Other EPA Comment Codes and Descriptions: 1260 1.1.1.5 More certainty/stringency is needed 

Comment: II. Regulatory Oversight 

57
Regional Advisory Boards: Establish a Carbon Capture and Sequestration Advisory 

Board for each of the EPA's ten regional offices (according to guidelines under 

40 CFR 25.7), in order to optimally administer a "Tailored Requirements 

Approach" that applies national standards which are adaptive to a variety of 

regional differences in geological formations, natural resources, weather 

patterns, industrial operations, and applicable state laws. 

Response: EPA clarifies that establishing a Carbon Capture and Sequestration Advisory Board is

out of the scope of the GS rulemaking. EPA adds that 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. As part of this adaptive rulemaking approach, EPA will

consult with a variety of stakeholders, including the National Drinking Water Advisory Council,

associations and organizations, ORD, and experts to ensure that implementation of the national Class

VI program is based on the best available science.

Commenter Name: Anonymous2 Letter

ID: 0133

Commenter Organization: Sierra Club National Global Warming and Energy

Committee and Sierra Club California-Nevada Regional Conservation Committee on

Energy and Climate Change

Comment

ID: 21606

Other EPA Comment Codes and Descriptions: 1260 1.1.1.5 More certainty/stringency is needed 

Comment: Regulatory Oversight 

D. Regional Advisory Boards 

Recommendation D: Establish a Carbon Capture and Sequestration Advisory Board 

for each of the EPA's ten regional offices (according to guidelines under 40 CFR 

25.7), in order to optimally administer a "Tailored Requirements Approach" that 

applies national standards which are adaptive to a variety of regional 

differences in geological formations, natural resources, weather patterns, 

industrial operations, and applicable state laws. 

Response: EPA will continue to consult with a variety of stakeholders, including the National

Drinking Water Advisory Council, associations and organizations, ORD, and experts; review

permits; and continue to hold workshops to build expertise and ensure that implementation of the

national program is based on the best available science. 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.

Commenter Name: Kristin Henry Letter ID: 0242

Commenter Organization: Sierra Environmental Law Program, Sierra Club Comment ID: 23334

Comment: IX. The Proposed Rule’s Public Participation Opportunities are Insufficient. 

Public acceptance of CCS is a major issue. Innumerable reports and 

recommendations from the federal government and top scientists, institutions and 

workgroups stress that the success of a CCS program will depend heavily on 

public acceptance. The National Academy of Sciences cautioned "the storage 

58
program cannot be successful if a significant fraction of the public views it as 

dangerous or unacceptable. Thus, CCS technologies must not only be safe and 

effective, it must be explainable to the public in such as way as to instill 

confidence that they are in fact safe and effective." [FN41] The International 

Risk Governance Council recommends that regulatory frameworks must include 

"effective risk communication to engage and educate the public, involve all 

stakeholders in risk-related decisions, and build confidence in the institutions 

governing CCS." [FN42] The Clean Air Act Advisory Committee’s Advanced Coal 

Technology Work Group’s January 2008 report similarly highlighted the need for 

public outreach. [FN43] The need to gain public acceptance will be especially 

crucial with early projects, which supports our earlier recommendation that EPA 

make these crucial early decisions with the help of a technical advisory board. 

[FN41: U.S. GAO Report. CLIMATE CHANGE: Federal Actions will Greatly Affect the 

Viability of Carbon Capture and Storage As a Key Mitigation Option, GAO-08-1080, 

September 2008 (quoting National Academy of Sciences, Prospective Evaluation).] 

[FN42: IRGC, Regulation of Carbon Capture and Storage, p. 24, available at 

http://www.irgc.org/IMG/pdf/Policy_Brief_CCS.pdf (last visited December 17, 

2008).] 

[FN43: January 29, 2008 Final Report, available at 

http://www.epa.gov/air/caaac/coaltech/2008_01_final_report.pdf (last visited 

December 17, 2008).] 

EPA should ensure that the proposed rule includes ample public involvement at 

the earliest possible stages to gain public trust and acceptance of its 

decisions. This gives the community time to process the complicated and 

voluminous information involved in a siting decision and contact other officials 

about issues not within EPA’s authority. It also will mitigate some 

controversial issues and potentially avoid litigation and other delays. 

Response: EPA disagrees that the public participation requirement provided for in the rule is

insufficient. However, EPA recognizes that the initial phases of site evaluation and site selection

may begin in advance of permit application submission. The public may become aware of these

activities and begin to have questions or concerns about the pending project. For this reason,

outreach and education—which are outside of, but complementary to, the public notification process

—can help clarify project details and avoid public misperceptions about the nature and safety of GS

projects. This may also benefit the owner or operator by improving local acceptance of the site. 

EPA encourages but does not require operators and permitting agencies to begin involving the public

by providing information as early in the GS project development process as possible. Involving the

public in the permitting process is an important aspect of both UIC Program requirements and EPA's

overall mission. The public will also have the opportunity to submit written comments and, in many

cases, attend hearings on proposed GS projects during formal public comment periods. Although

permit application information will not be made available as it is submitted to the Director,

permitting authorities must follow the public participation requirements for UIC permits specified in

40 CFR Part 124 which generally requires that owners or operators publish a public notice that

includes information about where interested parties can obtain copies of the draft permit and

application. 

59
Comment Code: 2000 1.5 Need for a New Class of Injection Well 

Individual Comments

Commenter Name: Michael H. Cochran Letter ID:

0108

Commenter Organization: Bureau of Water, Division of Environment, Kansas

Department of Health & Environment (KDHE)

Comment

ID: 21945

Other EPA Comment Codes and Descriptions: 2140 1.6.2 Depleted oil and gas reservoirs; 2146

1.6.2.2 Comments opposing injection into depleted reservoirs 

Comment: 5. Consider developing regulations that actually address an injection/withdrawal 

type project much similar to a natural gas porosity storage system. In this 

scenario the CO2 is contained in a limited, defined geologic trap and the system 

is designed to inject the CO2 or withdraw the CO2 as needed. 

Response: EPA clarifies that the GS rule addresses injection wells designed for long-term

sequestration of carbon dioxide; the Class VI designation and permit requirements are not applicable

to owners or operators that plan to withdraw carbon dioxide. 

The Agency believes that the nature and risks of CO2 injection for the primary purpose of long-term

storage poses unique risks that may endanger USDWs, and therefore has developed new Class VI

regulations to address these risks. Furthermore, the GS requirements adequately address these risks.

Commenter Name: Brianne Metzger Letter ID: 0151

Commenter Organization: Spectra Energy Corp Comment ID: 21856

Comment: C. 

D. EPA Should Create A Subclass Of Class II Or Class VI UIC Wells For Sour CO2 

Injection Operations Irrespective Of Whether Such Gas Is From Hydrocarbon 

Production. 

Raw natural gas often contains significant impurities such as CO2, H2S, and N2. 

Sour CO2 is also generated as a by-product from the gas sweetening process used 

to produce natural gas suitable for transmission and sale. The composition of 

the sour CO2 mixture is highly variable based on geological conditions, the 

composition of the raw natural gas, and the processing technology. Raw gas 

that is naturally higher in H2S results in higher concentrations of H2S as a 

percentage composition of the sour CO2. Although, in Western Canada, CO2 often 

accounts for most of the sour CO2 composition (i.e., as much as 80%), at some 

facilities, such as our Kwoen plant, the CO2 composition of the gas waste is 

only around 20%. 

Historically, most of the waste gases from natural gas processing were disposed 

of by flaring, but more recently, great strides have been made toward injecting 

the gas wastes into deep geologic formations. Thus, the injection and longterm storage of sour CO2 is an appropriate analog to CO2 geological 

sequestration. Sour CO2 disposal is not only an integral part of natural gas 

production, but the management and disposal of such gases will be an integral 
part of making GS technologies viable as well. The IPCC noted that it will be 

important to reduce the acidic gas components of flue gas from coal-fired power 

plants before CO2 removal, because the acidic gas reduces the absorption 

capacity of the solvent used to remove CO2. Thus, power plants that seek to 

employ GS technologies will be required to eliminate and dispose of these gases 

along with the CO2. It is unclear whether or not the acidic qualities of flue 

gases would constitute a characteristic hazardous waste based on low pH or 

toxicity. Notwithstanding, UIC injection requirements that govern CO2 disposal 

must govern acidic gases of all kinds as part-and-parcel to the GS Rule. These 

requirements must be flexible and workable, similar to those of Class II 

requirements. 

Despite the potentially hazardous characteristics of sour CO2, Section 3001(b) 

(2)(A) of RCRA currently exempts sour CO2 from Subtitle C hazardous waste 

regulations provided the gas is related to oil or natural gas exploration or 

production and processing.[10] Although not regulated under RCRA, sour gas 

injection for purposes of disposal is regulated under the UIC Class II well 

program. EPA has raised some concern regarding the toxicity and potential 

safety of sour CO2 in the context of the UIC program.[11] However, the 

management and injection of such gases has been performed safely over the last 

two decades. And, in fact, the IPCC has equated the health, safety and 

environmental risks of sour CO2 disposal with that of GS operations, if 

properly managed.[12] The history and strong safety record of sour CO2 

operations in North America provides a compelling argument to exempt CO2 

injection from other non-exempt sources and activities. 

In the U.S., the management and disposal of sour CO2 has largely been 

implemented at the state level pursuant to both federal UIC and state 

underground injection laws. Some states like Wyoming regulate sour CO2 

injection solely pursuant to the UIC Class II requirements. Whereas, other 

states, such as Texas, overlay the UIC program requirements with additional 

state law requirements. For example, Texas law governs injection where the 

H2S content is at least 100 parts per million. See 16 TEX. ADMIN. CODE § 

3.36(a)(2)(C) (2008). In addition to the baseline UIC Class II requirements, 

operators are required to assess the potential impact of releases by 

determining a "radius of exposure" based on concentrations of 100 ppm and 500 

ppm. They are also required to post warning signs in public areas, provide 

wellhead security, and use corrosion-resistant materials. Contingency planning 

to prepare for and respond to potentially dangerous releases is major component 

of sour gas injection operations. 

Canada has far more experience with sour CO2 disposal than the U.S. As noted 

earlier, in Western Canada, as of 2007, there were 44 sour CO2 injection 

projects operational, injecting into 51 different formations. A total of 27 of 

these operations inject sour CO2 into deep saline formations, while 19 sites 

inject into depleted oil and gas reservoirs, and the remaining sites inject 

into the water leg of depleted oil and gas reservoirs. See Carbon Dioxide 

Capture and Storage, IPCC, Annex I, Properties of CO2 and Carbon-Based Fuels, 

November 2005. Carbonates form the reservoir at 29 sites and quartz-rich 

sandstone at 21 sites. The overlying unit in most formations is shale, and the 
others consist of tight limestone, evaporites, and anhydrites. Since the early 

1990s, when injection first commenced, 2.5 Mt of CO2 and 2.0 Mt of H2S have 

been safely injected without any detectable leaks. 

Similar to the U.S., Alberta has a program to regulate activities related to 

the injection and disposal of fluids, although there are differences between 

the two programs. The Energy Resources Conservation Board (ERCB), an 

independent quasi-judicial agency of the Government of Alberta, is responsible 

for regulating Alberta’s energy resources (oil, natural gas, oil sands, coal) 

and pipelines, as well as approving applications for oil and gas operations 

including underground injection.[13] 

The ERCB is responsible for reviewing and approving all injection wells 

consistent with specific technical requirements pertaining to cementing and 

casing, logging to evaluate hydraulic isolation and casing integrity, and other 

testing for initial pressure, monitoring, area of review, and operating 

parameters. The ERCB has the authority to require a well to be abandoned where 

the location or condition of that well may become a source of water pollution. 

Alberta’s philosophy for deepwell disposal of oilfield and industrial wastes is 

a safe and viable disposal option where wells are properly constructed, 

operated, and monitored. Regulatory activities for sour gas focus on the 

following: 

. wellbore integrity to ensure initial and ongoing containment of the disposal 

fluid to protect groundwater; . formation suitability and hydraulic containment 

to ensure initial and ongoing confinement of the disposal fluid to protect 

groundwater; . suitability of the waste stream for deepwell disposal 

considering the nature of the fluid, the integrity of the well, and alternative 

waste management options; . maximum H2S fraction, maximum wellhead injection 

pressure, and rate and maximum injection volume; and . reporting and 

manifesting of disposed wastes. 

In addition, operators of sour gas processing facilities must submit monthly 

reports which provide detailed information regarding the nature of the 

operations, including the amount and quality of the sour CO2 injection. 

Sour CO2 disposal, storage or cycling operations in Alberta are regulated as a 

Class III well (different than UIC Class III), which under Alberta’s laws are 

wells primarily used for the injection of hydrocarbons or inert or other gases. 

On balance, the injection of sour CO2 is regulated no differently than 

hydrocarbons. Similar to the U.S., sour CO2 disposal is not managed as a 

hazardous waste, which is regulated under Alberta’s Class Ia well requirements 

that are the most stringent. 

Under Alberta’s regulations, matters of fluid-fluid, fluid-equipment, and 

fluid-formation compatibility are left primarily to the disposal well operator, 

with provincial regulators relying on operating and monitoring requirements to 

provide for early detection and mitigation of potential problems. Alberta 

prohibits the subsurface injection of numerous wastes, including municipal or 

industrial sewage, lube oils, spent solvents, diesel invert drilling fluids, 
and surface run-off water that meets surface discharge criteria (some of these 

prohibited because they are treated as recyclable). All other waste fluids, 

including sour CO2, are suitable for deepwell disposal if they have a pH 

between 4.5 and 12.5. 

Based on the collective experience of U.S. and Canadian operators involving the 

safe disposal of many metric tons of sour CO2 over the last two decades, EPA 

should consider developing a subclass of wells under Class II or Class IV for 

the injection of sour CO2. There is simply no compelling basis for the EPA to 

regulate any acidic gases as hazardous waste under the burdensome Class I 

requirements. 

10 See U.S. EPA, Regulatory Determination for Oil and Gas Geothermal, 

Development and Production Wastes, 53 Fed. Reg. 254476, 25454 (July 6, 1988). 

EPA made the regulatory determination in 1988 to exempt sour CO2 from hazardous 

waste requirements. Presumably, sour CO2 would be subject to RCRA’s hazardous 

waste requirements if they were not generated during oil and gas production. 

11 See Vulnerability Evaluation Framework for Geologic Sequestration of Carbon 

Dioxide, U.S. EPA Technical Support Document, Report No. EPA430-R-08-009, July 

10, 2008. 

12 According to the IPCC, "[w]ith appropriate site selection based on available 

subsurface information, a monitoring program to detect problems, a regulatory 

system, and the appropriate use of remediation methods to stop or control CO2 

releases if they arise, the local health, safety and environment risks of 

geologic storage would be comparable to risks of current activities such as 

natural gas storage, [enhanced oil recovery], and deep underground disposal of 

acid gas." IPCC 2005. 

13 See Injection and Disposal Wells, Well Classifications, Completions, Logging 

and Testing Requirements, ERCB, March 1994. Available at 

http://www.ercb.ca/docs/ Documents/directives/Directive051.pdf. 

Response: The Agency believes that the nature and risks of CO2 injection for the primary purpose

of long-term storage poses different risks than those associated with injection for the primary

purpose of EOR, and therefore has developed new Class VI regulations to address these unique risks.

For example, the volume of CO2 anticipated to be injected for long-term storage is significantly

greater than for EOR operations. Reservoir pressure conditions will also be different, for example,

Class VI injection operations involve larger volumes of CO2 that will likely have higher pressures

within their storage formations than Class II ER projects. EPA adds that most sour gas (acid gas)

injection in the U.S. is permitted as Class II as defined under 40 CFR §144.6 of the UIC regulations

because the sour CO2 is typically injected associated with oil and gas exploration. The GS

requirements are not overly burdensome and 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 has taken the position that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program because of the differences in risk profiles

between EOR and long-term storage of CO2. The Agency disagrees that wells injecting CO2 for the
primary purpose of long-term storage should be regulated under Class II requirements. EPA

recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of

EOR, and that sites used for EOR may be suitable for GS and may be among the first Class VI

permitted sites. EPA also recognizes that a by-product of EOR activities is that a certain percentage

of the CO2 is trapped in the receiving formation.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24382

Comment: Rule Provision: 144.80(f) 

Proposed CCS Group Recommendations: (f) Class VI. Wells used 

for geologic sequestration of carbon dioxide. INJECTING A CARBON 

DIOXIDE STREAM FOR GEOLOGIC SEQUESTRATION EXCEPT THOSE WELLS

DESCRIBED IN 

SUBSECTION (B)(4) OF THIS SECTION OR OTHERWISE EXCLUDED FROM THIS CLASS. 

Basis for CCS Group Comments: The changes to (b) and (f) are to recognize that 

EOR can have a storage component, which is consistent with EPA’s intent as 

expressed in the preamble. It is widely recognized that CO2 based EOR can 

provide a significant early opportunity for carbon storage. As EPA correctly 

recognizes, CO2 EOR operations can have a significant storage component through 

capillary trapping or other mechanisms. Operators experience supports this 

approach as they have seen that between 1/3 to 1/2 of the injected CO2 in EOR 

operations is trapped within the receiving formation during CO2 EOR operations. 

Following abandonment of EOR operations, assuming the CO2 not trapped in the 

receiving formation, has not been produced for use in another field, essentially 

all of the CO2 that has been injected can be permanently stored. 

We recommend that all GS into basalts, coal seams, and salt domes be conducted 

under Class V as experimental wells initially and then as commercial scale Class 

V wells/projects if the experimental projects demonstrate that these sites can 

be suitable for geological sequestration while preventing endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain enough 

experience to develop suitable permitting requirements for such wells and to 

tailor those requirements at both the pilot and commercial scales until the 

agencies are ready to adapt the Class VI regulations. 

Additionally, there should not be a blanket prohibition concerning injection 

above USDW’s or at specific depths. This requirement is not necessary for the 

protection of USDWs and would remove a vast number of viable formations from 

consideration. Industry has shown that it can operate CO2 injection wells in an 

EOR context without endangering USDWs that are located below the injection zone. 

An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

measures that would provide real assurance of formation integrity and require 

operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. Instead, operators should be able to 

show adequate containment to prevent endangerment of USDWs both above and below 
the injection zone used for geologic sequestration. 

Response: As described above regarding the suggested edit at 144.6(b), EPA did not make the

suggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of longterm storage should be regulated under Class II requirements.

Regarding injection into basalts, coal seams, and salt domes, EPA clarifies that the GS rule does not

categorically preclude injection of CO2 into any non-USDW formation types. The purpose of the GS

rule is to ensure protection of USDWs from endangerment, and the rule requires that owners or

operators demonstrate that wells are sited in suitable systems with geologic formations to receive

and confine injected CO2, as required at §146.83 of the GS rule. The Class VI siting, well

construction and operation, monitoring and testing, and post-injection site care and site closure

requirements are designed to ensure that injected CO2 remains within the target formation. If an

owner or operator can demonstrate to the Director's satisfaction that GS in coal seams, basalts, salt

domes, or shales can be accomplished in a manner that protects USDWs and meets all of the

requirements of the GS rule, the project may be permitted as a Class VI well. 

EPA acknowledges that there may be unknown risks associated with GS, particularly regarding GS

into formations such as coal seams, basalts, and salt domes, which have been the subject of limited

experimental projects in the past. EPA anticipates that in the short-term, GS into these types of

formations will continue to be experimental (i.e., if they are to test GS technologies and collect data),

and will likely be permitted as Class V experimental technology wells and be subject to UIC

Program Guidance #83. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to Class VI projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs. The final GS rule at §146.95 establishes a

process by which owners or operators can seek a waiver of the Class VI injection depth

requirements. The waiver approach requires the submission of extensive, site-specific information

(in conjunction with the permit application submittal) to demonstrate that injection of CO2 into a

formation that is above or between USDWs can be done in a manner that is protective of USDWs.

The requirements are designed to ensure that the owner or operator, the Director, and the Regional

Administrator consider, on a site specific basis, the implications, benefits, and challenges associated

with GS and ensuring water availability and USDW protection. 

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24390

Comment: Rule Provision: 146.5(f) 

Proposed CCS Group Recommendations: (f) Class VI. Wells used 

for geologic sequestration of carbon dioxide beneath the lowermost formation 

containing an underground source of drinking water (USDW). INJECTING A CARBON 

DIOXIDE STREAM FOR GEOLOGIC SEQUESTRATION EXCEPT THOSE WELLS

DESCRIBED IN 

SUBSECTION (B)(4) OF THIS SECTION OR OTHERWISE EXCLUDED FROM THIS CLASS. 
Basis for CCS Group Comments: The changes to (b) and (f) are to recognize that 

EOR can have a storage component, which is consistent with EPA’s intent as 

expressed in the preamble. It is widely recognized that CO2 based EOR can 

provide a significant early opportunity for carbon storage. As EPA correctly 

recognizes, CO2 EOR operations can have a significant storage component through 

capillary trapping or other mechanisms. Operators experience supports this 

approach as they have seen that between 1/3 to 1/2 of the injected CO2 in EOR 

operations is trapped within the receiving formation during CO2 EOR operations. 

Following abandonment of EOR operations, assuming the CO2 not trapped in the 

receiving formation, has not been produced for use in another field, essentially 

all of the CO2 that has been injected can be permanently stored. 

We recommend that all GS into basalts, coal seams, and salt domes be conducted 

under Class V as experimental wells initially and then as commercial scale Class 

V wells/projects if the experimental projects demonstrate that these sites can 

be suitable for geological sequestration while preventing endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain enough 

experience to develop suitable permitting requirements for such wells and to 

tailor those requirements at both the pilot and commercial scales until the 

agencies are ready to adapt the Class VI regulations. 

Additionally, there should not be a blanket prohibition concerning injection 

above USDW’s or at specific depths. This requirement is not necessary for the 

protection of USDWs and would remove a vast number of viable formations from 

consideration. Industry has shown that it can operate CO2 injection wells in an 

EOR context without endangering USDWs that are located below the injection zone. 

An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

measures that would provide real assurance of formation integrity and require 

operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. Instead, operators should be able to 

show adequate containment to prevent endangerment of USDWs both above and below 

the injection zone used for geologic sequestration. 

Response: As described above regarding the suggested edit at 144.6(b), EPA did not make the

suggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of longterm storage should be regulated under Class II requirements.

Regarding injection into basalts, coal seams, and salt domes, EPA clarifies that the GS rule does not

categorically preclude injection of CO2 into any non-USDW formation types. The purpose of the GS

rule is to ensure protection of USDWs from endangerment, and the rule requires that owners or

operators demonstrate that wells are sited in suitable systems with geologic formations to receive

and confine injected CO2, as required at §146.83 of the GS rule. The Class VI siting, well

construction and operation, monitoring and testing, and post-injection site care and site closure

requirements are designed to ensure that injected CO2 remains within the target formation. If an

owner or operator can demonstrate to the Director's satisfaction that GS in coal seams, basalts, salt

domes, or shales can be accomplished in a manner that protects USDWs and meets all of the

requirements of the GS rule, the project may be permitted as a Class VI well. 
EPA acknowledges that there may be unknown risks associated with GS, particularly regarding GS

into formations such as coal seams, basalts, and salt domes, which have been the subject of limited

experimental projects in the past. EPA anticipates that in the short-term, GS into these types of

formations will continue to be experimental (i.e., if they are to test GS technologies and collect data),

and will likely be permitted as Class V experimental technology wells and be subject to UIC

Program Guidance #83. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to Class VI projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs. The final GS rule at §146.95 establishes a

process by which owners or operators can seek a waiver of the Class VI injection depth

requirements. The waiver approach requires the submission of extensive, site-specific information

(in conjunction with the permit application submittal) to demonstrate that injection of CO2 into a

formation that is above or between USDWs can be done in a manner that is protective of USDWs.

The requirements are designed to ensure that the owner or operator, the Director, and the Regional

Administrator consider, on a site specific basis, the implications, benefits, and challenges associated

with GS and ensuring water availability and USDW protection. 

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24395

Comment: Rule Provision: 146.81(a) 

Proposed CCS Group Recommendations: THESE SECTIONS MAY REQUIRE FURTHER

REVISIONS 

TO PROVIDE CONFORMING LANGUAGE. 

Basis for CCS Group Comments: The multi-stakeholder group has agreed that 

proposed language describing wells in classification (b)(4) establishes a 

"bright line" definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the 

current requirements of Class II. We have also agreed that the wells used for GS 

in oil and gas reservoirs that do not meet the criteria of (b)(4) should be 

subject to additional requirements. We have tentatively defined such wells as 

wells used "for geologic sequestration in oil and gas formations and where the 

criteria of paragraph (b)(4) are not met." But we have not yet attempted to 

define what specific requirements should apply to these wells. We are committed 

to working toward agreement on those requirements (probably within a Class II 

context) and submitting the results of that effort to EPA by February 28, 2009 

for your consideration. 

In addition, we recommend that all GS into basalts, coal seams, and salt domes 

be conducted under Class V as experimental wells initially and then as 

commercial scale Class V wells/projects if the experimental projects demonstrate 

that these sites can be suitable for geological sequestration while preventing 
endangerment of USDWs. 

Response: As described above, EPA agrees that injection of CO2 for the primary purpose of

enhancing oil and gas recovery should remain under the Class II Program. However, the Agency

disagrees that wells injecting CO2 for the primary purpose of long-term storage should be regulated

under Class II requirements. EPA recognizes that the oil and gas industry has decades of experience

injecting CO2 for the purpose of EOR, and that sites used for EOR may be suitable for GS and may

be among the first GS sites. EPA also recognizes that a by-product of EOR activities is that a certain

percentage of the CO2 is trapped in the receiving formation. 

The Agency believes that the nature and risks of CO2 injection for the primary purpose of long-term

storage pose different risks than injection for the primary purpose of ER, and therefore has

developed new Class VI regulations to address these unique risks. For example, the volume of CO2

anticipated to be injected for long-term storage is significantly greater than for EOR operations.

Reservoir pressure conditions will also be different, with Class VI injection operations involving

large volumes of CO2 and likely having higher pressures within their storage formations than Class

II EOR projects. 

As described above, EPA clarifies that the GS rule does not categorically preclude injection of CO2

into any non-USDW formation types. If an owner or operator can demonstrate to the Director's

satisfaction that GS in coal seams, basalts, salt domes, or shales can be accomplished in a manner

that protects USDWs and meets all of the requirements of the GS rule, the project may be permitted

as a Class VI well. 

The Agency anticipates that, in the near-term, most GS in unmineable coal seams will continue to be

experimental. Such projects may be permitted as Class V experimental technology wells if they are

of an experimental nature (i.e., to test GS technologies and collect data). EPA will continue to

review data on early GS projects, including those in unmineable coal seams, to determine whether

the appropriate amount and types of information and documentation are required and being

collected. EPA plans, every six years, to collect and review data on GS projects to determine whether

the appropriate amount and types of information and appropriate documentation are being collected,

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

Commenter Name: A. James Mayer Letter ID: 0230

Commenter Organization: A. J. Mayer International on behalf of the American

Energy Security Initiative

Comment ID:

21886

Other EPA Comment Codes and Descriptions: 1250 1.1.1.4 Flexibility is needed (performancebased standards) 

Comment: 3. EPA should begin with a Class II injection well framework to assure that the 

rules are flexible enough to consider site-specific characteristics and 

knowledge gained from the extensive CO2 history and the ongoing demonstration 

and pilot projects. 

Response: EPA agrees that owners and operators of Class II wells have experience that will be

helpful in implementing the Class VI requirements, but EPA disagrees that the risks posed by longterm storage of CO2 for GS can be addressed under existing UIC requirements, such as those for

Class II wells. EPA believes that there are significant differences between how projects are operated,

as well as the risks posed by these different injection activities. The new tailored approach of the GS

rule was designed to address the general risks deep injection may pose to USDWs and was tailored
specifically to address the risks posed by long-term storage of CO2 (i.e., very large volumes, very

long time-periods, and reservoir pressure conditions).

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Furthermore, EPA agrees that flexibility is important for regulating GS activities. EPA has taken a

regulatory approach which promotes USDW protection, incorporates flexibility or the discretion of

the permitting authority when appropriate, seeks to limit burden on owners or operators and

permitting agencies, and provides a foundation for national consistency in permitting of GS projects.

For example, under the final rule, many of the permit requirements must be established through sitespecific plans (e.g., AOR and corrective action plan, testing and monitoring plan, etc.) developed by

the owner or operator and approved by the Director. Consequently EPA expects that owners or

operators will consult with the Director as they develop, implement, and update these plans.

Additionally, the Director has the discretion to approve alternatives to the requirements in some

cases. For example, the Director may in certain situations modify the length of the post-injection site

care period or approve an alternative post-injection site care timeframe as part of the permitting

process under §146.93, allow the use of alternate methods for mechanical integrity testing under

§146.89, or grant waivers from the requirement to inject below the lowermost USDW under

§146.95.

Commenter Name: Kurt Waltzer Letter ID: 0250

Commenter Organization: Clean Air Task Force Comment ID: 22292

Comment: Class VI is appropriately grouped with Class I Hazardous, Class II and Class III 

wells in the modification or revocation and reissuance provisions 

We believe that EPA in §144.39 has appropriately listed Class VI alongside other 

injection classes for which a permit can be revoked and reissued for a specific 

cause (alterations to the facility, new information received and regulatory 

changes since the permit issued. This is necessary in order to ensure that Class 

VI regulations are adaptive, reflecting experience in GS as it is amassed. We do 

not support Class VI being listed alongside classes for which the permittee has 

control over whether reissue or modification would occur through requesting or 

agreeing to it. 

Response: EPA agrees the Director should have the ability to revoke and reissue a permit for Class

VI wells and has retained this provision in the final rule.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24833
Comment: Rule Provision: 144.6 

EPA Proposal: 3. Section 144.6 is amended as follows: 

Revising paragraph (e); and 

b. Adding new paragraph (f). 

* * * * * 

(e) Class V. Injection wells not included in Class I, II, III, IV, or VI. 

Specific types of Class V injection wells are described in § 144.81. 

(f) Class VI. Wells used for geologic sequestration of carbon dioxide beneath 

the lowermost formation containing a USDW. 

GWPC Recommendations: (4) For enhanced recovery of oil or natural gas where 

geologic sequestration is occurring during or in connection with enhanced 

recovery of oil or natural gas provided (i) there is reasonable expectation of 

more than insignificant future production volumes or rates as a result of carbon 

dioxide injection and (ii) operating pressures are no higher than reasonably 

necessary to produce such volumes or rates; 

(f) Class VI. Wells injecting a carbon dioxide stream for geologic 

sequestration except those wells described in subsection (b)(4) of this section 

or otherwise excluded from this Class. 

Rationale: There should not be a blanket prohibition concerning injection above 

USDW’s or at specific levels. The determination of injection zones should be 

based upon appropriate containment. This is especially true in light of recent 

calls for changes in the definition of a USDW to include formations greater than 

10K PPM TDS and the fact that several states including Wyoming and California 

might be prevented from instituting geologic sequestration as a practical matter 

if injection were limited to above USDW’s due to the great depth of some USDW’s. 

This would create a situation where otherwise good injection zones are 

artificially excluded, thus decreasing the overall availability of geologic 

sequestration in the U.S. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements. The waiver approach requires the submission of extensive, site-specific information

(in conjunction with the permit application submittal) to demonstrate that injection of CO2 into a

formation that is above or between USDWs can be done in a manner that is protective of USDWs.

The requirements are designed to ensure the owner or operator, the Director, and the Regional

Administrator consider, on a site specific basis, the implications, benefits, and challenges associated

with GS and ensuring water availability and USDW protection. 

Comment Code: 2020 1.5.1 Support Class VI designation 
Individual Comments

Commenter Name: Gerald C. Blount Letter ID: 0107

Comment ID: 21940

Other EPA Comment Codes and Descriptions: 1420 1.2.1.1 Support the GS rulemaking 

Comment: As a concerned practicing geoscientist I believe it is reasonable to 

regulate the geologic storage of CO2 by creating a new well class (Class VI) 

within the Underground Injection Control (UIC) program and it is necessary to 

protect underground drinking water sources. However, it may not be appropriate 

to categorically limit storage to formations with water salinity greater than 

10,000 parts per million. 

Response: EPA agrees that the creation of a new injection well class (VI) under the existing UIC

Program is necessary to enable the use of GS as a climate change mitigation technology in a manner

that protects USDWs from endangerment. EPA agrees that the UIC Program, under the authority of

the SDWA, provides a strong framework for regulating injection of CO2 for GS and adds that the

GS regulation tailors the UIC requirements to address the unique issues associated with large-scale

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.

Comments related to redefining or modifying the definition of USDWs under 40 CFR 144.3 are

outside the scope of the rulemaking. The GS rule, as part of the UIC program regulations, continues

the program’s tradition of ensuring the protection of USDWs by prohibiting injection of carbon

dioxide into USDWs. EPA clarifies that all Class VI injection must be into non-USDWs, which are

formations with water salinity greater than 10,000 parts per million. The mandate as required by the

SDWA of any Federally approved UIC Program (whether administered by a State, Territory, Tribe

or EPA) is the protection of USDWs. This includes not only those formations that are presently

being used for drinking water, but also those that can reasonably be expected to be used in the

future. EPA has established through its UIC regulations that USDWs are underground aquifers with

less than 10,000 milligrams per liter (mg/L) total dissolved solids (TDS) and which contain a

sufficient quantity of ground water to supply a public water system (40 CFR 144.3). EPA defines

saline formations as deep and geographically extensive sedimentary rock layers saturated with

waters or brines that have a high total dissolved solids (TDS) content (i.e., over 10,000 mg/L TDS). 

EPA notes that owners or operators of Class II wells have the option to expand aquifer exemptions

that have already been granted for purposes of Class VI injection under §144.7(d). The owner or

operator must meet the requirements found in 146.4(d).

Commenter Name: Jill D. Jonas Letter ID: 0135

Commenter Organization: Wisconsin Dept. of Natural Resources (WDNR) Comment ID: 21667

Comment: Class VI GS Wells 

The Department also supports creation of a sixth well class for managing GS 

injection. The physical and chemical characteristics of the carbon dioxide 

stream, long capture times required, volume to be injected, and various geologic 
settings proposed for injection suggest that an adaptive regulatory approach is 

most effective for managing GS wells. Creating a separate well classification 

will enable EPA and other permitting authorities to enact the necessary 

technical criteria for site characterization, area of review and corrective 

action, well construction and operation, compliance monitoring, and postinjection site care with minimal impact on existing regulations for injection 

practices in the other established well classes. 

Response: EPA acknowledges the comment and agrees that tailored requirements for Class VI wells

are necessary to address the unique nature of injecting large volumes of CO2 and to ensure that

USDWs are protected from endangerment. The Class VI requirements are appropriate because of the

unique nature and risks of CO2 injection for long-term storage (e.g., large injection volumes, long

project duration, and reservoir pressure conditions). The GS rule contains tailored requirements for

the permitting, geologic site characterization, AoR and corrective action, well construction,

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of GS wells that directly address issues unique to the nature of large-scale CO2 injection for

GS.

Commenter Name: Kenneth Alexander Letter ID: 0146

Commenter Organization: Old Dominion Electric Cooperative (ODEC) Comment ID: 21706

Other EPA Comment Codes and Descriptions: 1420 1.2.1.1 Support the GS rulemaking 

Comment: ODEC greatly appreciates EPA's work toward developing a regulatory framework for 

underground injection of CO2. EPA's decision to develop regulations under the 

UIC program and to develop a new Class VI for CO2GS well is appropriate. ODEC 

Response: EPA acknowledges the comment and agrees that tailored requirements for Class VI wells

are necessary to address the unique nature of injecting large volumes of CO2 and to ensure that

USDWs are protected from endangerment. The Class VI requirements are appropriate because of the

unique nature and risks of CO2 injection for long-term storage (e.g., large injection volumes, long

project duration, and reservoir pressure conditions). The GS rule contains tailored requirements for

the permitting, geologic site characterization, AoR and corrective action, well construction,

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of GS wells that directly address issues unique to the nature of large-scale CO2 injection for

GS.

Please also see the discussion of EPA’s Final Regulatory Approach in the preamble to the final GS

rule.

Commenter Name: Bonnie Lovelace Letter ID: 0152

Commenter Organization: Montana Department of Environmental Quality

(MDEQ)

Comment ID:

22101

Comment: GENERAL COMMENTS: 1 . MDEQ agrees with the EPA approach to designating a

new UIC 

class. The specific construction requirements, monitoring, modeling and analysis 

and nontraditional identification of the Area of Review all support a new 

class definition. 

Response: EPA acknowledges the comment and agrees that tailored requirements for Class VI wells
are necessary to address the unique nature of injecting large volumes of CO2 and to ensure that

USDWs are protected from endangerment. The Class VI requirements are appropriate because of the

unique nature and risks of CO2 injection for long-term storage (e.g., large injection volumes, long

project duration, and reservoir pressure conditions). The GS rule contains tailored requirements for

the permitting, geologic site characterization, AoR and corrective action, well construction,

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of GS wells that directly address issues unique to the nature of large-scale CO2 injection for

GS.

Commenter Name: Jeff Moseley Letter ID: 0155

Commenter Organization: Greater Houston Partnership (GHP) Comment ID: 21255

Comment: 2. Establish a new Class VI well category tailored for large-scale CO2 

sequestration projects that builds on the existing UIC framework including the 

oil and gas industry's over 35 years of experience injecting CO2 and EOR. 

Response: EPA acknowledges the comment and agrees that tailored requirements for Class VI wells

are necessary to address the unique nature of injecting large volumes of CO2 and to ensure that

USDWs are protected from endangerment. The Class VI requirements are appropriate because of the

unique nature and risks of CO2 injection for long-term storage (e.g., large injection volumes, long

project duration, and reservoir pressure conditions). The GS rule contains tailored requirements for

the permitting, geologic site characterization, AoR and corrective action, well construction,

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of GS wells that directly address issues unique to the nature of large-scale CO2 injection for

GS.

Commenter Name: Ellen Gilinsky Letter ID: 0157

Commenter Organization: Virginia Department of Environmental Quality

(DEQ)

Comment ID:

21263

Comment: wells. The Virginia Department of Environmental Quality (DEQ) supports the 

establishment of a new class ofwells specifically for the purpose of sequestering 

carbon dioxide. The pilot projects will provide additional information to 

Response: EPA acknowledges the comment and agrees that tailored requirements for Class VI wells

are necessary to address the unique nature of injecting large volumes of CO2 and to ensure that

USDWs are protected from endangerment. The Class VI requirements are appropriate because of the

unique nature and risks of CO2 injection for long-term storage (e.g., large injection volumes, long

project duration, and reservoir pressure conditions). The GS rule contains tailored requirements for

the permitting, geologic site characterization, AoR and corrective action, well construction,

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of GS wells that directly address issues unique to the nature of large-scale CO2 injection for

GS.

Commenter Name: Skiles Boyd Letter ID: 0160

Commenter Organization: DTE Energy Comment ID: 21273

Comment: pose a substantial risk to public health and the environment. Enhanced Oil 

Recovery (EOR) has been successfully deployed in our state for over 15 years 

without incident to the public or the environment. DTE Energy supports the 

establishment of the new Class VI well category for CO2 injection but advises 
Response: The Class VI requirements are appropriate because of the unique nature and risks of CO2

injection for long-term storage (e.g., large injection volumes, long project duration, and reservoir

pressure conditions). The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS.

Commenter Name: Joseph Eutizi Letter ID: 0161

Commenter Organization: San Miguel Electric Cooperative, Inc Comment ID: 21280

Other EPA Comment Codes and Descriptions: 1420 1.2.1.1 Support the GS rulemaking 

Comment: San Miguel greatly appreciates EPA's work toward developing a regulatory 

framework for underground injection of CO2. EPA's decision to develop 

regulations under the UIC program and to develop a new Class VI for CO2 GS well 

is appropriate. San Miguel also appreciates EPA's recognition that while the new 

Response: EPA acknowledges the comment and agrees that tailored requirements for Class VI wells

are necessary to address the unique nature of injecting large volumes of CO2 and to ensure that

USDWs are protected from endangerment. The Class VI requirements are appropriate because of the

unique nature and risks of CO2 injection for long-term storage (e.g., large injection volumes, long

project duration, and reservoir pressure conditions). The GS rule contains tailored requirements for

the permitting, geologic site characterization, AoR and corrective action, well construction,

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of GS wells that directly address issues unique to the nature of large-scale CO2 injection for

GS.

Commenter Name: Sandi Tabor Letter ID: 0162

Commenter Organization: Lignite Energy Council (LEC) Comment ID: 21297

Comment: 1.Establishment of the new Class VI injection well/Class II permit for EOR 

continued/Grandfathering the construction requirements of existing Class I and 

II wells -The LEC supports the establishment of a new injection well class for 

those wells not associated with EOR provided that EPA recognizes the need for 

flexibility within the regulation of the new class. We agree that where there is 

Response: EPA acknowledges the comment and agrees that tailored requirements for Class VI wells

are necessary to address the unique nature of injecting large volumes of CO2 and to ensure that

USDWs are protected from endangerment. The Class VI requirements are appropriate because of the

unique nature and risks of CO2 injection for long-term storage (e.g., large injection volumes, long

project duration, and reservoir pressure conditions). The GS rule contains tailored requirements for

the permitting, geologic site characterization, AoR and corrective action, well construction,

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of GS wells that directly address issues unique to the nature of large-scale CO2 injection for

GS.

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: James Stine Letter ID: 0163

Commenter Organization: National Rural Electric Cooperative Association

(NRECA)

Comment ID:

21309

Other EPA Comment Codes and Descriptions: 1420 1.2.1.1 Support the GS rulemaking 

Comment: NRECA greatly appreciates EPA's work toward developing a regulatory framework 

for underground injection of CO2. EPA's decision to develop regulations under 

the UIC program and to develop a new Class VI for CO2 GS well is appropriate. 

Response: EPA acknowledges the comment and agrees that tailored requirements for Class VI wells

are necessary to address the unique nature of injecting large volumes of CO2 and to ensure that

USDWs are protected from endangerment. The Class VI requirements are appropriate because of the

unique nature and risks of CO2 injection for long-term storage (e.g., large injection volumes, long

project duration, and reservoir pressure conditions). The GS rule contains tailored requirements for

the permitting, geologic site characterization, AoR and corrective action, well construction,

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of GS wells that directly address issues unique to the nature of large-scale CO2 injection for

GS.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23361

Other EPA Comment Codes and Descriptions: 5600 2.11 Comments related to UIC Program

primacy for Class VI wells 

Comment: General Issues Related to Classification and Regulation of CO2 GS Wells -- Pg. 20 

APPA believes the creation of a new category of wells under the UIC Program for 

long-term storage of CO2 is appropriate and agrees with EPA that the Final Rule 

should create a delegable program and encourage the adoption and 

implementation of that program by States. 

Response: EPA acknowledges the comment and agrees that tailored requirements for Class VI wells

are necessary to address the unique nature of injecting large volumes of CO2 and to ensure that

USDWs are protected from endangerment. The Class VI requirements are appropriate because of the

unique nature and risks of CO2 injection for long-term storage (e.g., large injection volumes, long

project duration, and reservoir pressure conditions). The GS rule contains tailored requirements for

the permitting, geologic site characterization, AoR and corrective action, well construction,

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of GS wells that directly address issues unique to the nature of large-scale CO2 injection for

GS.

EPA agrees with commenters on the importance of states having primacy for GS wells given the

variety of geologic settings in which GS will be applied. EPA recognizes that State, Tribal,
Territorial and DI UIC Program Directors are in the best position to evaluate the unique issues

related to well depth, geology, and hydrogeology that are posed by a Class VI well. Some degree of

flexibility is needed for Class VI wells because each decision made will be site-specific and

conditions will differ from state to state. The GS rule balances the need for these site-specific

decisions with the need for minimum standards to ensure national consistency. 

The Agency believes that it is important for states to use their unique efficiencies to promote

adoption of this burgeoning and important technology, while assuring that USDWs are protected

from endangerment through the UIC regulatory framework. EPA encourages states to accept primacy

for Class VI, and believes that, due to the importance of implementing an effective, comprehensive,

and seamless CCS program, States should be provided the flexibility to obtain primacy for Class VI

only. 

However, given the potential for CCS (encompassing capture, transportation, and geologic

sequestration) to be an important part of a national priority to address climate change, EPA believes

that providing states the flexibility to obtain primacy for Class VI wells independently of other well

classes can help foster effective management of CCS. EPA believes that allowing independent Class

VI primacy may encourage states to take responsibility for implementation of Class VI regulations

and provide for a more comprehensive approach to managing CCS projects by promoting the

integration of GS activities under SDWA into a broader framework for managing CCS. Furthermore,

GS operations involve ancillary activities (e.g., pipeline operations, pore space ownership, land use

rights, and surface access) for which states can call upon other authorities that exist at the state level

(but outside UIC authority) to provide a more comprehensive CCS management approach.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23378

Comment: 6. APPA enthusiastically supports a UIC Class VI permit classification despite 

our questions about feasibility and commercial deployment of the technology in 

2008. Development of a permitting system soon is necessary to provide regulatory 

certainty to the first generation demonstration projects that are essential 

before the commercial development of larger scale plants. 

Response: As described above, EPA acknowledges the comment and agrees that tailored

requirements for Class VI wells are necessary to address the unique nature of injecting large volumes

of CO2 and to ensure that USDWs are protected from endangerment.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23388

Comment: But, APPA does believe that the CCS plants that will be proven viable deserve a 

permitting mechanism under the EPA’s proposed Class VI program. APPA has no 

hesitation about a Class VI permitting system. APPA encourages the U.S. EPA to 

finalize this new category as soon as possible to facilitate the permitting and 

construction of first generation U.S. demonstration projects. 

Response: As described above, EPA agrees that tailored requirements for Class VI wells are

necessary to address the unique nature of injecting large volumes of CO2 and to ensure that USDWs

are protected from endangerment.
Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23408

Comment: General Issues Related to Classification and Regulation of CO2 GS Wells 

APPA believes the creation of a new category of wells under the UIC Program for 

long-term storage of CO2 is appropriate. Id. at 43502 

Response: As described above, EPA agrees that tailored requirements for Class VI wells are

necessary to address the unique nature of injecting large volumes of CO2 and to ensure that USDWs

are protected from endangerment.

Commenter Name: Erik Silvola Letter ID: 0171

Commenter Organization: Great River Energy Comment ID: 23437

Other EPA Comment Codes and Descriptions: 1420 1.2.1.1 Support the GS rulemaking 

Comment: Great River Energy (GRE) greatly appreciates EPA's work toward developing a 

regulatory framework for underground injection of CO2. EPA's decision to develop 

regulations under the UIC program and to develop a new Class VI for CO2 GS well 

is appropriate. GRE also appreciates EPA's recognition that while the new 

regulations at hand must be within the scope of the SDWA, there are a number of 

very important issues (such as long term liability) that are outside the scope 

of the act but are highly pertinent to developing a viable GS program and we are 

glad that EPA is willing to discuss these issues as part of this regulatory 

proposal. 

Response: EPA acknowledges the comment and agrees that tailored requirements for Class VI wells

are necessary to address the unique nature of injecting large volumes of CO2 and to ensure that

USDWs are protected from endangerment. The Class VI requirements are appropriate because of the

unique nature and risks of CO2 injection for long-term storage (e.g., large injection volumes, long

project duration, and reservoir pressure conditions). The GS rule contains tailored requirements for

the permitting, geologic site characterization, AoR and corrective action, well construction,

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of GS wells that directly address issues unique to the nature of large-scale CO2 injection for

GS.

EPA understands that there are a number of issues that are outside of the scope of this rulemaking

and SDWA authority that are important to commenters, such as long-term liability. EPA clarifies

that long-term liability is a broad concept that includes many mechanisms, however, for purposes of

the SDWA there are liability mechanisms available under §§ 1423 and 1431 for those activities that

endanger USDWs. EPA recognizes that liability is an important issue to owners or operators but the

Agency does not have authority under the SDWA to transfer long-term liability from owners or

operators to the state or federal government. Therefore, liability remains with the owner or operator.

Please see the preamble discussion on financial responsibility and liability.

Commenter Name: James Taft Letter ID: 0172

Commenter Organization: Association of State Drinking Water Administrators

(ASDWA)

Comment ID:

23449

Other EPA Comment Codes and Descriptions: 1330 1.1.3.1 Support use of GS in general; 1420

1.2.1.1 Support the GS rulemaking 
Comment: Overall Comments 

ASDWA and its members appreciate EPA’s efforts to develop this rule under very 

limited time constraints and agree with EPA’s plan to create a new class of 

wells for carbon dioxide geologic sequestration sites. States believe that all 

appropriate steps need to be taken to ensure the effectiveness of Carbon Capture 

and Sequestration as a tool to mitigate greenhouse gas emissions, as well as 

avoid potential unintended consequences that could have a negative impact on 

Underground Sources of Drinking Water (USDW). Additional research and data are 

needed to ensure that this rule is fully protective of all potential drinking 

water sources. 

Response: EPA acknowledges the comment and agrees that tailored requirements for Class VI wells

are necessary to address the unique nature of injecting large volumes of CO2 and to ensure that

USDWs are protected from endangerment. The Class VI requirements are appropriate because of the

unique nature and risks of CO2 injection for long-term storage (e.g., large injection volumes, long

project duration, and reservoir pressure conditions). The GS rule contains tailored requirements for

the permitting, geologic site characterization, AoR and corrective action, well construction,

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of GS wells that directly address issues unique to the nature of large-scale CO2 injection for

GS. 

EPA agrees that continued research in all GS associated fields will be integral to development of GS

technology. EPA is aware of research by other federal agencies, industry, international parties, and

academia related to GS, including projects that address many of the topics suggested by commenters.

EPA published a Notice of Data Availability (NODA) 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 (in Escatawpa, Mississippi; the Aneth Field in Paradox Basin, southeast Utah; and the Pump

Canyon Site, New Mexico). In the NODA and Request for Comment, EPA also described two

studies by the Lawrence Berkeley National Laboratory on the potential effects of CO2 injection on

ground water and surrounding formations to determine the potential for impacts on USDWs and

human health in the event that a GS project is not properly sited, operated, or managed. 

To protect USDWs from endangerment and meet the potentially fast pace of GS deployment, EPA is

using an adaptive approach to regulating CO2 injection for GS. The Agency plans to, every six

years, collect and review data on GS projects to determine whether the appropriate amount and types

of information and appropriate documentation are being collected, and to determine if modifications

to the requirements are appropriate or necessary. An adaptive approach will allow regulatory

development to proceed in time to meet the current and future demands for Class VI permits, while

EPA continues to gather data from pilot projects and other research as it becomes available.

Commenter Name: James Rower Letter ID: 0173

Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23474

Comment: 3. Classification and Regulation of CO2 GS Wells 

USWAG believes the creation of a new category of wells under the UIC Program for 

long-term storage of CO2 is appropriate. 73 Fed. Reg. at 43502. USWAG agrees 

with the Proposal's structure that would only apply the requirements for Class 

VI wells to those wells specifically permitted for purposes of geologic 
sequestration, while maintaining a distinct permitting classification (Class II) 

for the injection of CO2 for the purposes of enhanced oil and gas recovery. Id. 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. EPA also agrees that the nature and risks of CO2 injection for long term storage is

different from Class II CO2 injection for ER, and that tailored requirements for GS wells are

appropriate and necessary to protect USDWs from endangerment. For this reason, the Agency

tailored UIC requirements for Class VI wells that address the general risks deep injection may pose

to USDWs and specifically address the unique nature of CO2 GS (i.e., very large volumes, very long

time-periods, and reservoir pressure conditions). 

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: Pamela Faggert Letter ID: 0175

Commenter Organization: Dominion Comment ID: 23517

Comment: Specific Comments on the Proposal 

1. Creation of Class VI Category 

Dominion supports the creation of a new class of injection wells for CO2 

injection and storage. Establishing a new Class VI class enables appropriate 

regulations based on the unique characteristics of CO2 sequestration, namely the 

buoyancy, corrosivity, and anticipated volumes. Including CO2 GS in the existing 

Class I, Hazardous Waste regulations would unnecessarily stigmatize CCS, 

creating public perception problems and would be inappropriate for protection of 

USDW. 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS. EPA also agrees that Class I

regulations are not appropriate to fully address GS wells and would not necessarily be protective of

USDWs.

Commenter Name: Kenneth Nemeth Letter ID: 0176

Commenter Organization: Southern States Energy Board Comment ID: 23535
Other EPA Comment Codes and Descriptions: 1210 1.1.1 Comments about the proposed rule 

Comment: The proposed Federal requirements under the Safe Drinking Water Act (SDWA) for 

underground injection of carbon dioxide for the purpose of geologic 

sequestration is a step forward. SSEB supports the establishment of a new Class 

VI designation specifically dealing with GS. A new class of wells with minimum 

technical criteria for the geologic site characterization, fluid movement, area 

of review (AoR) and corrective action, well construction, operation, mechanical 

integrity testing, monitoring, well plugging, post-injection site care, and site 

closure for the purposes of protecting USDWs will advance GS projects. The 

proposed rule will help to ensure consistency in permitting of 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’s regulatory provisions should accurately 

reflect the low risk profile that exists for CO2 exposure from a GS project. 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS.

Commenter Name: Quinlan J. Shea Letter ID: 0177

Commenter Organization: Edison Electric Institute Comment ID: 23576

Comment: II. Specific Comments 

A. General Comments on Class VI Approach 

EPA‘s proposed rules would create a new class of injection wells--Class VI--for 

CO2 injection and storage. EEI is generally supportive of this approach, as it 

allows regulations to be tailored to fit the needs of such projects and helps to 

avoid potential issues of inaccurate public perception that might arise from 

including it within an existing well class (in particular Class I). As is 

discussed throughout these comments, EEI views accurate public perception of the 

nature of CCS as critical to its successful deployment. 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23810

Comment: D. WELL CLASS APPROACH 

The creation of a new class of wells (Class VI) to cover underground injection 
of CO2 outside the context of EOR (existing Class II or Class V wells already 

permitted are properly left outside the scope of the Class VI proposal) is a 

reasonable approach due to the unique features of CCS, including the low 

viscosity of supercritical CO2, its high buoyancy, and injection volumes that 

could dwarf those of other well classes. There is important recognition that 

such an approach should not impede the development of CCS technology but should 

"support the development of a key climate change" risk "mitigation 

technology".[FN6] The CCS Alliance agrees that where there is an EOR component 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. EPA also agrees that the nature and risks of CO2 injection for long term storage is

different from Class II CO2 injection for ER, and that tailored requirements for GS wells are

appropriate and necessary to protect USDWs from endangerment. For this reason, the Agency

tailored UIC requirements for Class VI wells that address the general risks deep injection may pose

to USDWs and specifically address the unique nature of CO2 GS (i.e., very large volumes, very long

time-periods, and reservoir pressure conditions). 

EPA clarifies that the purpose of the GS rule is not to incentivize the use of GS. The purpose of the

GS rule is to ensure that, where GS is deployed, it is conducted in a manner that does not endanger

USDWs.

Commenter Name: G. Graham Holden Letter ID: 0189

Commenter Organization: Oglethorpe Power Corporation Comment ID: 25242

Other EPA Comment Codes and Descriptions: 1410 1.2.1 Comments in support of

EPA/rulemaking 

Comment: It appears that GS of CO2 from fossil-fueled power plants will be a critical 

part of any national strategy to control greenhouse gas emissions. Oglethorpe 

appreciates EPA's work toward developing a regulatory framework for underground 

injection of CO2. EPA's decision to develop regulations under the UIC program 

and to develop a new class of injection wells (Class VI) for CO2 GS seems 

appropriate. We also support EPA's recognition that while the new regulations at 

Response: EPA acknowledges the comment and believes that the creation of a new injection well

class (VI) under the existing UIC Program is necessary to deployment of GS as a climate change

mitigation technology in a manner that protects USDWs from endangerment. EPA agrees that the

UIC Program, under the authority of the SDWA, provides a strong framework for regulating

injection of CO2 for GS and adds that the GS regulation tailors the UIC requirements to address the

unique issues associated with large-scale 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24360

Comment: Rule Provision: 144.1 

Proposed CCS Group Recommendations: Support revision to include a sixth class of 
Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS.

Commenter Name: Chris M. Hobson Letter ID: 0201

Commenter Organization: Southern Company Comment ID: 22157

Other EPA Comment Codes and Descriptions: 1614 1.3.1.2 Impurities in captured CO2; purity

standards for CO2 

Comment: Classification of CO2 GS Wells and Interaction with Other Regulatory Regimes 

Southern Company supports EPA's approach of creating a new category of wells 

under the UIC program for the long-term sequestration of C02. Id. at 43502. The 

new Class VI designation is appropriate for the injection of CO2 streams 

captured from an emission source, including incidental associated substances 

derived from source materials and the capture process, as well as substances 

added to the stream to facilitate the injection process. As EPA observes, the 

addition of such substances may sometimes prove a necessary step in the 

injection process. See id. at 43493. Accordingly, the removal of these 

incidental associated substances should only be required as necessary to avoid 

interference with capture, transportation, injection and containment of CO2 

streams. 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS.

Commenter Name: Thomas Curtis Letter ID: 0204

Commenter Organization: American Water Works Association (AWWA) Comment ID: 22181

Comment: - A Class VI regulatory permit system is needed to advance geosequestration 

demonstration projects. 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS.

EPA clarifies that the purpose of the GS rule is not to incentivize or encourage the use of GS. The

purpose of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that does

not endanger USDWs. 
Commenter Name: Diane VanDe Hei Letter ID: 0213

Commenter Organization: Association of Metropolitan Water Agencies

(AMWA)

Comment ID:

22930

Comment: Class VI wells: AMWA agrees with EPA’s proposal to have CO2 geosequestration 

wells permitted under a new UIC category -- Class VI -- as this is a new type of 

injection well. However, as there is limited modeling or monitoring data 

specific to UIC of CO2 available, this data gathering and modeling must occur. 

AMWA has additional comments about research needs below. 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS. EPA adds that it continues to

monitor research being conducted on GS and will use this to inform its adaptive rulemaking

approach. EPA plans, every six years, to collect and review data on GS projects to determine

whether the appropriate amount and types of information and appropriate documentation are being

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

Commenter Name: Steven B. Corneli Letter ID: 0234

Commenter Organization: NRG Energy, Inc. Comment ID: 23159

Other EPA Comment Codes and Descriptions: 1420 1.2.1.1 Support the GS rulemaking 

Comment: NRG appreciates the substantial efforts which have been part of this proposal 

development governing CO2 injection for the purpose of GS. As a company, NRG is 

committed to effectively addressing climate change, and believes that GS is a 

critical component for the reduction of CO2 emissions. In general, NRG supports 

and commends the efforts of the EPA to develop a rational approach that would 

(1) create a new category of injection wells (i.e., Class VI) under the 

Underground Injection Control (UIC) Program and (2) establishes Federal 

regulations that are specifically tailored to CO2 injection for GS. However, we 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS.

The EPA believes the final rulemaking falls within EPA’s authority under the SDWA. EPA clarifies

that the SDWA provides EPA with the authority to develop federal minimum requirements for

underground injection, such as GS, that are directly related to protecting USDWs from

endangerment. Thus, EPA does not have authority under the SDWA to address other issues related

to CCS, such as capture and transportation.

Commenter Name: James T. Sims Letter ID: 0249

Commenter Organization: Western Business Roundtable Comment ID: 22259

Other EPA Comment Codes and Descriptions: 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: 1. Don’t Chill On-Going Enhanced Oil Recovery (EOR) Activities -- EPA’s search 

for a regulatory structure to manage geologic sequestration of CO2, in the 

context of CO2 capture initiatives contemplated in CCS initiatives, has resulted 

in this proposal to create a new SDWA UIC "Class VI" category . This effort 

reflects the fact that geologic sequestration wells do not fall neatly into any 

of the current SWDA UIC classes. We understand that rationale and generally 

support the distinction being drawn. In fact, we want to make sure that the 

distinction is drawn clearly enough that it doesn’t confuse or impede the 

existing CO2 uses, such as EOR, already covered under Class II of the UIC 

regime. 

Response: EPA believes that injection for the primary purpose of long-term storage is sufficiently

different from Class II EOR operations and warrants tailored requirements. EPA agrees that the

nature and risks of CO2 injection for long-term storage is different from Class II CO2 injection for

EOR, and that tailored requirements for GS wells are appropriate and necessary to protect USDWs

from endangerment. For this reason, the Agency tailored UIC requirements for Class VI wells that

address the general risks deep injection may pose to USDWs and specifically address the unique

nature of CO2 GS (i.e., very large volumes, very long time-periods, and reservoir pressure

conditions). 

EPA clarifies that the purpose of the GS rule is not to incentivize or encourage the use of GS or to

address the use of pore space. The purpose of the GS rule is to ensure that, where GS is deployed, it

is conducted in a manner that does not endanger USDWs. 

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: Kurt Waltzer Letter ID: 0250

Commenter Organization: Clean Air Task Force Comment ID: 22279

Comment: The statute provides additional direction to EPA in developing its rules - the 

rules must "permit or provide for consideration of varying geologic, 

hydrological, or historical conditions, in different States and in different 

areas within a State," [FN15] and they are not to "interfere with or impede" 

underground injections for the purposes of "the secondary or tertiary recovery 

of oil or natural gas, unless such requirements are essential to assure that 

underground sources of drinking water will not be endangered by such injection." 

[FN16] While EPA is not free to exempt a particular class of injection entirely 

from rulemaking, the Agency is authorized to tailor the UIC rules to the 

specific geologic conditions and also to particular injection activities. The 

statute clearly authorizes EPA to create a new class or classes of UIC wells for 
the purpose of CO2 sequestration. 

[FN15: 42 U.S.C. § 300h(b)(3)(A).] 

[FN16: Id. § 300h(b)(2)(B).] 

Response: EPA agrees that the final GS rulemaking, which creates a new class of well, is absolutely

within the Agency’s authority provided under the SDWA. EPA agrees that tailored requirements for

Class VI wells are necessary to address the unique nature of injecting large volumes of CO2 and to

ensure that USDWs are protected from endangerment. The GS rule contains tailored requirements for

the permitting, geologic site characterization, AoR and corrective action, well construction,

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of GS wells that directly address issues unique to the nature of large-scale CO2 injection for

GS.

Commenter Name: Kurt Waltzer Letter ID: 0250

Commenter Organization: Clean Air Task Force Comment ID: 22282

Other EPA Comment Codes and Descriptions: 1200 1.1 General comments about the rulemaking 

Comment: D. General Comments 

Timing of promulgation 

The proposed rule is based on a risk management approach and is written in a way 

that should avoid unintended consequences to USDWs. It is important to bear in 

mind that CO2 injection projects can already be permitted today. While this may 

be adequate to protect USDWs in certain cases, it is in the interests of the 

public (and the regulated industry) to have a new injection class, designed from 

the outset with the particular characteristics of GS in mind, as soon as 

possible. This is necessary in order provide certainty and adequately safeguard 

public health and the environment. If the final rule incorporates changes 

concerning the adaptive nature of the rule and permits, as our Environmental NGO 

Group suggests, the Agency, and its state counterparts, will be able to deal 

with such unintended consequences to USDWs through the rule’s performancebased 

provisions, review and a possible reissuance of permits if necessary, and by 

revising the rule text if appropriate. 

Response: EPA agrees that the tailored requirements for Class VI wells, pursuant to the final GS

rulemaking, are necessary to address the unique nature of injecting large volumes of CO2 and to

ensure that USDWs are protected from endangerment, and that a new well Class specific to GS is

appropriate. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS.

EPA adds that it continues to monitor research being conducted on GS and will use this to inform its

adaptive rulemaking approach. EPA plans, every six years, to collect and review data on GS projects

to determine whether the appropriate amount and types of information and appropriate

documentation are being collected, and to determine if modifications to the requirements are

appropriate or necessary.
Commenter Name: Kurt Waltzer Letter ID: 0250

Commenter Organization: Clean Air Task Force Comment ID: 22283

Other EPA Comment Codes and Descriptions: 1200 1.1 General comments about the rulemaking;

1640 1.3.4 CERCLA issues (seeking comment) 

Comment: We consider the Phase III Deployment Phase of the Department of Energy’s (DOE) 

Regional Partnership Program to be very worthwhile, but we do not consider the 

completion of this program to be a prerequisite for either commercial 

implementation of CCS or for the promulgation of a sound and protective rule. 

The DOE’s program has limited funds available through appropriations, and its 

demonstration projects will be of limited scale and duration. In addition, it 

focuses as much or more on the optimum way to apply existing technologies as it 

does on fundamental research or even demonstrations that particular technologies 

"work." Our scientific and practical understanding and experience in GS itself, 

as well as in related underground injection activities, is sufficient to 

construct and operate the first large-scale, commercial plants in the U.S., 

provided they are regulated adequately. In that respect, we do not consider the 

proposed rule premature, but a very timely and necessary development. 

The rule itself, rather than individual permits, should assure that Class VI 

permits do not allow responsible parties to avoid CERCLA liability on grounds 

that a release constitutes a "federally permitted release" 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS.

EPA believes, as supported by the rule's administrative record, that sufficient data and experience

currently exist to develop UIC regulations for GS wells. The GS rulemaking builds upon decades of

knowledge about safe injection practices. While developing the GS regulation, EPA has evaluated

relevant GS research, including projects conducted by the seven regional carbon sequestration

partnerships funded by the U.S. Department of Energy and coordinated through the National Energy

Technology Laboratory (NETL), and several international projects. Additionally, EPA's Office of

Water continues to fund research at the Lawrence Berkeley National Laboratory examining the

effects of CO2 interaction with ground water aquifers and any potential mobilization of trace

elements that may occur.

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). Therefore, Class VI

requirements and permits will need to be carefully structured to ensure that they do not 'authorize'

inappropriate releases, and would need to prevent potential releases from the well which are outside

the scope of the Class VI permit. Furthermore, EPA is promulgating the GS rule under the authority

of the SDWA. To the extent the commenter is seeking interpretations of CERCLA and its related

provisions, such as the definition of a federally permitted release, such interpretations are beyond 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.

Regarding long term liability, once an owner or operator has met all regulatory requirements under

Part 146 for Class VI wells and the Director has approved site closure pursuant to requirements at

§146.93, the owner or operator will generally no longer be subject to enforcement for regulatory

noncompliance. Furthermore, their financial instrument as required under §146.85 will be released if

it was not used. However, even if a site closure is approved under §146.93, an owner or operator

may be held liable for regulatory noncompliance (including violation of 40 CFR 144.12) in certain

circumstances. For example, an owner or operator may be held liable for regulatory noncompliance

even after site closure was approved if the Director relied on erroneous information (e.g., erroneous

modeling data) provided by the owner or operator when approving site closure. 

Separate from EPA's authority to enforce regulatory compliance, an owner or operator may be

subject to a §1431 response order even after proper site closure is approved under §146.93. Under

§1431 the Administrator may require an owner or operator to take necessary response measures if he

or she receives information that a contaminant is present or is likely to enter a public water system

or an USDW, which may present an imminent and substantial endangerment to the health of

persons, and the appropriate State and local authorities have not acted to protect the health of such

persons. The action may include issuing administrative orders or commencing a civil action for

appropriate relief against the owner or operator of a Class VI well. If the owner or operator fails to

comply with the order, they may be subject to a civil penalty for each day in which such violation

occurs or failure to comply continues. 

Furthermore, after site closure an owner or operator may remain liable under tort and other remedies,

or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. §§7401-7671;

CERCLA, 42 U.S.C. §9601-9675; and RCRA, 42 U.S.C. §6901-6992. EPA does not have authority

to transfer SDWA or other legal liability for Class VI wells to the State or federal government or a

third-party fund. See the final rule preamble for further discussion of EPA's final approach.

EPA recognizes the significant amount of data generated by the DOE partnerships and agrees that

sufficient data have been collected to inform the final GS rule. EPA has evaluated permits and

reviewed operational data and information associated with the seven regional carbon sequestration

partnerships funded by the U.S. Department of Energy and coordinated through the National Energy

Technology Laboratory. EPA believes that these projects form a solid basis for finalizing the GS

requirements, and agrees there is no reason to wait until all phases of the DOE demonstration tests

are complete.

Commenter Name: Walter L. Baker Letter ID: 0253

Commenter Organization: Utah Division of Water Quality Comment ID: 22341

Comment: APPROPRIATENESS OF CLASS VI CLASSIFICATION FOR GS WELLS 

We support the creation of a new class of injection well for carbon dioxide 

geologic sequestration wells. This action acknowledges the unique nature of and 

purpose for this new well class and facilitates the development of enabling 

regulations for the rapid deployment of CCGS projects. We do not, however, 
Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24832

Comment: Rule Provision: 144.1 

EPA Proposal:2. Section 144.1 is amended as follows: 

Adding new paragraph (f)(1) (viii); and b. Revising the first two sentences in 

paragraph (g) introductory text. 

* * * * * 

(f) * * * 

(1) * * * 

(viii) Subpart H of this part sets forth requirements for owners or operators of 

Class VI injection wells. 

* * * * * 

(g) Scope of the permit or rule requirement. The UIC Permit Program regulates 

underground injections by six classes of wells (see definition of "well 

injection," § 144.3). The six classes of wells are set forth in § 144.6. All 

owners or operators of these injection wells must be authorized either by permit 

or rule by the Director. * * * 

GWPC Recommendations: Support revision to include a sixth class of wells. 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS.

Commenter Name: William Herz Letter ID: 0266

Commenter Organization: The Fertilizer Institute Comment ID: 22876

Comment: Proposal to Create New Category of Injection Well-Class VI Wells 

EPA is proposing to create a new category of injection well under its existing 
UIC Program with new federal requirements to allow for the injection of CO2 for the 

purpose of GS. EPA proposes to tailor existing UIC program components so that they 

are appropriate for the unique nature of injecting large volumes of CO2 into a 

variety of geological formations to ensure that underground sources of drinking 

water (USDW) are not endangered (73 Fed. Reg. 43,495). 

TFI supports establishing a new class of well - Class VI - specifically for CO2 

geologic sequestration and maintaining injection of CO2 for the purposes 

of enhanced oil and gas recovery under the Class II program, and the potential for 

an expanded UIC program to support development of a key climate change mitigation 

technology. TFI generally agrees with the Agency's stated goal of providing 

"certainty to industry and the public about requirements that would apply to 

injection, by providing consistency in requirements across the U.S., and 

transparency about what requirements apply to owners or operators" (73 Fed. Reg. 

43,496). As discussed further in our comments, TFI requests additional 

clarification so that these regulations also provide certainty, consistency 

and transparency regarding which requirements apply to potential upstream 

industrial sources such as fertilizer manufacturers. 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS. EPA believes that the GS

rulemaking does provide certainty, consistency and transparency for those parties who will be

regulated under the rulemaking.

EPA also agrees that the nature and risks of CO2 injection for long term storage is different from

Class II CO2 injection for ER. For this reason, the Agency tailored UIC requirements for Class VI

wells that address the general risks deep injection may pose to USDWs and specifically address the

unique nature of CO2 GS (i.e., very large volumes, very long time-periods, and reservoir pressure

conditions). 

EPA clarifies that the Class VI requirements do not apply to the source of the CO2, only to the

owner or operator of the injection well.

Commenter Name: George Peridas Letter ID: 0534

Commenter Organization: Natural Resources Defense Council (NRDC) Comment ID: 21461

Comment: I think this concludes my technical points. I think there are many good elements 

in this rule. The proposal of the new injection class itself is a very good one. 

The requirements for extensive monitoring is another example. This architectural 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS. EPA agrees that the testing
and monitoring requirements are an important element of the GS rulemaking.

Comment Code: 2040 1.5.2 Oppose Class VI designation 

Individual Comments

Commenter Name: Michael H. Cochran Letter ID:

0108

Commenter Organization: Bureau of Water, Division of Environment, Kansas

Department of Health & Environment (KDHE)

Comment

ID: 21944

Comment: 4. The establishment of the precedence of developing a new well class when a 

unique or unusual well type is encountered. We believe the existing well 

classification framework can address this well type, thus simplifying 

administration of this type of well. 

144.1, 146.6, 144.15: Same comment as for item # 4 under the general comments. 

144.80, 146.5: Same as for144.1, 146.6 , 144.15. 

Response: EPA disagrees that the existing well class classification can address injection of CO2 for

long-term storage because there are significant differences between how projects are operated, as

well as the risks posed by these different injection activities. The new tailored approach of the GS

rule is designed to address the general risks deep injection may pose to USDWs and is tailored

specifically to address the risks posed by long-term storage of CO2 (i.e., very large volumes, very

long time-periods, and reservoir pressure conditions).

Comment Code: 2044 1.5.2.2 Oppose Class VI/ Support Class II 

Individual Comments

Commenter Name: Herbert Skolnick, Ph.D. Letter ID: 0110

Commenter Organization: Group Against Smog and Pollution, Inc. (GASP) Comment ID: 22037

Other EPA Comment Codes and Descriptions: 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: The Need for Class VI Wells: 

In the 2005 Energy Policy Act, Congress gave the Department of Energy the 

mission to investigate the gathering, transportation and injection of CO2 into 

oil and gas fields to increase production.[FN 4: 42 U.S.C. 15910.] On September 

6, 2006, the DOE announced its own program with a dual purpose of storing CO2 

and using the gas for enhanced oil recovery.[FN 5: DOE - Fossil Energy Techline: 

A Two-For-One Solution 

http://fossil.energy.gov/news/techlines/2006/06050-DOE_Awards_EOR_Project.html] 

According to the DOE, only about 10 per cent of the oil contained in an oil 
field is produced initially. Further production is achieved by injecting steam 

and water into the reservoir rock to overcome the viscosity of the remaining oil 

and move it into the collection wells. The oil industry has also been injecting 

CO2 into oil-bearing reservoirs since 1972. It has proven to be the most 

efficient enhanced recovery method to date. A major drawback has been its high 

cost even considering the current cost of oil. 

The CO2 used early on was produced from naturally CO2-containing rocks. To 

mitigate the cost of the CO2, a number of current projects use CO2 collected 

from the flue gasses of industrial plants, including the construction of 

dedicated pipelines to transport the CO2 to oil fields for enhanced recovery 

operations (one such example is the line from the Dakota Gasification Plant in 

Beulah, North Dakota to the Weyburn oil field in Saskatchewan, Canada. [FN 6: 

DOE, 2008, Fossil Energy: DOE's Oil Recovery R&D Programs, 

http://fossil.energy.gov/programs/oilgas/eor/ ] Ultimately with these additional 

technologies total production can be increased to 30 to 60% of the original oil 

in place. [FN 7: Id.] At the present time, given the current production of flue 

gas, there is enough storage space in existing depleted oil fields to sequester 

CO2 well into the next century.[FN 8: Schrag, D., Preparing to Capture Carbon, 

SCIENCE, p812-813, Feb. 9, 2007.] 

In contrast, the proposed Class VI wells will be newly drilled, and potential 

well sites will require extensive study to determine if the area’s geological 

characteristics are acceptable. Substantial savings of time and money would be 

realized if the EPA instead used the large number of Class II enhanced oil 

recovery/enhanced gas recovery wells that already exist. Oil and gas have been 

produced from some of these sites for many years, and the chemistry, reservoir 

characteristics, and geology of the sites have been extensively studied and 

understood. This is the class of wells that should be exploited first. 

A program with the dual mission of CO2 sequestration plus utilization of the gas 

in enhanced recovery of oil and gas has much more to offer in terms cost 

savings, time savings, and overall efficiency. Of equal significance is the 

increase in oil and gas production - particularly in light of concerns over US 

reliance on foreign oil and the present push for offshore drilling. The DOE 

estimates that given new CO2 technology existing oil fields can produce as much 

as an additional 500 thousand barrels per day by 2012 and as much as 2 million 

barrels per day by 2020.[FN 9: DOE supra note 6.] 

Finally, given the lower costs of CO2 sequestration in existing oil fields and 

the attendant increased oil production, sequestration in existing oil fields is 

also more likely to provide storage site operators with the financial resources 

necessary to ensure proper site closure and post-closure care, and to meet longterm financial assurance requirements. 

Response: EPA clarifies that the purpose of the GS rule is not to promote GS in one type of

formation over another. EPA clarifies that the purpose of the GS rule is to ensure protection of

USDWs from endangerment. 

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 believes that injection for the primary purpose of long term storage is sufficiently different

from Class II EOR operations and warrants tailored requirements. For example, the volume of CO2

anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir

pressure conditions will also be different, with Class VI injection operations involving large volumes

of CO2 and likely having higher pressures within their storage formations than Class II EOR

projects.

Commenter Name: Matt Toner Letter ID: 0117

Commenter Organization: Hydrogen Energy International Comment ID: 22062

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: In closing, Hydrogen Energy would like to applaud EPA for their effort to create 

an effective regulatory framework for the sequestration of Carbon Dioxide while 

protecting USDW's. However, we believes that EPA should go significantly further 

than the proposed regulation, by recognizing the potential for concurrent, CO2 

Injection for Enhanced Oil or Gas Recovery and Designed Storage and allowing for 

this dual purpose. Furthermore, EPA should facilitate grandfathering from dual 

purpose production and storage to storage-only sites when EOR/EGR operations are 

completed. 

Response: EPA clarifies that injection for enhanced recovery is permitted under Class II. EPA

disagrees that dual purpose underground injection should be authorized under the UIC program

because the unique risks posed by long term storage of CO2 for GS cannot be addressed under

existing UIC requirements, such as those for Class II wells. EPA believes that there are significant

differences between how projects are operated, as well as the risks posed by these different injection

activities. The new tailored approach of the GS rule was designed to address the general risks deep

injection may pose to USDWs and was tailored specifically to address the risks posed by long term

storage of CO2 (i.e., very large volumes, very long time-periods, and reservoir pressure conditions).

EPA notes that many Class II wells are designed and constructed to withstand exposure to CO2. 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 sitespecific flexibility. For more information, please see the discussion on transition of Class II wells in

the preamble to the final GS rule.

Commenter Name: William Kovacs Letter ID: 0148
Commenter Organization: U.S. Chamber of Commerce Comment ID: 21750

Comment: General and Specific Comments 

The Chamber notes that EPA already regulates CO2 injection for enhanced oil 

recovery (EOR). Existing "Class II" regulations governing injection of CO2 for 

EOR have proven successful at protecting underground sources of drinking water 

(USDW) and the health and safety of the public. Therefore, as an initial matter, 

EPA should consider whether it is really necessary to create a new class of 

wells and a new set of regulations for carbon sequestration purposes? 

Assuming EPA determines that a new class of wells is needed, despite existing 

Class II wells and regulations, the Chamber would also recommend EPA address the 

following concerns: 

Response: EPA does not believe that the unique risks posed by long term storage of CO2 for GS

can be adequately addressed under existing UIC requirements to protect USDWs from

endangerment, such as those for Class II wells. EPA believes that there are significant differences

between how projects are operated, as well as the risks posed by these different injection activities.

The new tailored approach of the GS rule was designed to address the general risks deep injection

may pose to USDWs and was tailored specifically to address the risks posed by long term storage of

CO2 (i.e., very large volumes, very long time-periods, and reservoir pressure conditions).

Commenter Name: Michel Paque Letter ID: 0297

Commenter Organization: Ground Water Protection Council Comment ID: 29316

Comment: March 31, 2009 

Cynthia C. Dougherty, Director 

Office of Ground Water and Drinking Water 

USEPA 

Ariel Rios Building 

1200 Pennsylvania Avenue, N. W. 

Washington, DC 20460 

Dear Ms. Dougherty: 

On December 23, 2008, the Ground Water Protection Council (GWPC) signed a letter 

submitted by a Multi-Stakeholder Group (MSG) supporting the concept of creating 

a new class of UIC wells to manage the geologic sequestration of carbon dioxide. 

As part of that letter, the GWPC also supported the development of new subclass 

of the Class II program for the purposes of geologic sequestration of carbon 

dioxide in oil and gas reservoirs. 

One of the topics discussed in the December 23 letter was the need for a way to 

determine when a well permitted under the Class II program would cross a "bright 

line" for purposes of distinguishing between a well used primarily for enhanced 

recovery and one used primarily for geosequestration. It is our understanding 

that members of the MSG are submitting language to EPA suggesting the criteria 

under which wells would transition from Class II Enhanced Recovery to a new 

class or subclass of well for geosequestration. 
Since much of the proposal being submitted by the MSG is based upon the concepts 

expressed by the GWPC in its December 23, 2008 submission of recommendation to 

EPA concerning the proposed Class VI rule, we expect to support some portion or 

portions of the MSG language. Regardless, to insure the process of rule 

development proceeds at an appropriate pace, we recommend that EPA publish the 

language proposed by the MSG as part of its Notice of Data Availability (NODA). 

The GWPC will continue to work with the MSG on this issue and we look forward to 

submitting more detailed comments as the process moves forward. 

Respectfully, 

Mike Paque 

GWPC Executive Director 

cc: Robert F. Van Voorhees 

Scott Anderson 

Response: EPA disagrees that wells injecting CO2 for the primary purpose of long term storage

should be regulated under Class II requirements. The Agency believes that the nature and risks of

CO2 injection for the primary purpose of long term storage poses different risks than injection for

the primary purpose of ER, and therefore has developed new Class VI regulations to address these

unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is

significantly greater than for ER operations. Reservoir pressure conditions will also be different, with

Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II ER projects.

The final Class VI regulations require that any owner or operator injecting CO2 for the primary

purpose of long term storage obtain a Class VI permit with some special consideration for the fact

that they are transitioning from a well not originally designed to meet Class VI requirements. The

Director has the authority to determine at what point a Class VI permit is required for those projects

that are transitioning from the primary purpose of EOR to long term storage of CO2. The final

regulation provides a set of technical factors for the Director to evaluate in making this

determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs

when there is an increased risk to USDWs as compared to traditional Class II operations while

allowing for site-specific flexibility. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS 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) 

Individual Comments

Commenter Name: Herbert Skolnick, Ph.D. Letter ID: 0110

Commenter Organization: Group Against Smog and Pollution, Inc. (GASP) Comment ID: 22037

Other EPA Comment Codes and Descriptions: 2044 1.5.2.2 Oppose Class VI/ Support Class II 

Comment: The Need for Class VI Wells: 
In the 2005 Energy Policy Act, Congress gave the Department of Energy the 

mission to investigate the gathering, transportation and injection of CO2 into 

oil and gas fields to increase production.[FN 4: 42 U.S.C. 15910.] On September 

6, 2006, the DOE announced its own program with a dual purpose of storing CO2 

and using the gas for enhanced oil recovery.[FN 5: DOE - Fossil Energy Techline: 

A Two-For-One Solution 

http://fossil.energy.gov/news/techlines/2006/06050-DOE_Awards_EOR_Project.html] 

According to the DOE, only about 10 per cent of the oil contained in an oil 

field is produced initially. Further production is achieved by injecting steam 

and water into the reservoir rock to overcome the viscosity of the remaining oil 

and move it into the collection wells. The oil industry has also been injecting 

CO2 into oil-bearing reservoirs since 1972. It has proven to be the most 

efficient enhanced recovery method to date. A major drawback has been its high 

cost even considering the current cost of oil. 

The CO2 used early on was produced from naturally CO2-containing rocks. To 

mitigate the cost of the CO2, a number of current projects use CO2 collected 

from the flue gasses of industrial plants, including the construction of 

dedicated pipelines to transport the CO2 to oil fields for enhanced recovery 

operations (one such example is the line from the Dakota Gasification Plant in 

Beulah, North Dakota to the Weyburn oil field in Saskatchewan, Canada. [FN 6: 

DOE, 2008, Fossil Energy: DOE's Oil Recovery R&D Programs, 

http://fossil.energy.gov/programs/oilgas/eor/ ] Ultimately with these additional 

technologies total production can be increased to 30 to 60% of the original oil 

in place. [FN 7: Id.] At the present time, given the current production of flue 

gas, there is enough storage space in existing depleted oil fields to sequester 

CO2 well into the next century.[FN 8: Schrag, D., Preparing to Capture Carbon, 

SCIENCE, p812-813, Feb. 9, 2007.] 

In contrast, the proposed Class VI wells will be newly drilled, and potential 

well sites will require extensive study to determine if the area’s geological 

characteristics are acceptable. Substantial savings of time and money would be 

realized if the EPA instead used the large number of Class II enhanced oil 

recovery/enhanced gas recovery wells that already exist. Oil and gas have been 

produced from some of these sites for many years, and the chemistry, reservoir 

characteristics, and geology of the sites have been extensively studied and 

understood. This is the class of wells that should be exploited first. 

A program with the dual mission of CO2 sequestration plus utilization of the gas 

in enhanced recovery of oil and gas has much more to offer in terms cost 

savings, time savings, and overall efficiency. Of equal significance is the 

increase in oil and gas production - particularly in light of concerns over US 

reliance on foreign oil and the present push for offshore drilling. The DOE 

estimates that given new CO2 technology existing oil fields can produce as much 

as an additional 500 thousand barrels per day by 2012 and as much as 2 million 

barrels per day by 2020.[FN 9: DOE supra note 6.] 

Finally, given the lower costs of CO2 sequestration in existing oil fields and 

the attendant increased oil production, sequestration in existing oil fields is 
also more likely to provide storage site operators with the financial resources 

necessary to ensure proper site closure and post-closure care, and to meet longterm financial assurance requirements. 

Response: EPA clarifies that the purpose of the GS rule is not to promote GS in one type of

formation over another. EPA clarifies that the purpose of the GS rule is to ensure protection of

USDWs from endangerment. 

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 believes that injection for the primary purpose of long term storage is sufficiently different

from Class II EOR operations and warrants tailored requirements. For example, the volume of CO2

anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir

pressure conditions will also be different, with Class VI injection operations involving large volumes

of CO2 and likely having higher pressures within their storage formations than Class II EOR

projects.

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114

Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22542

Comment: EOR INJECTION WELLS 

EPA notes at 73 FR 43526 "...CO2 injection. [as] .already practiced...(i.e. 

EOR), is expected to expand rapidly...." This statement can be interpreted to 

mean CO2 EOR will be come under the Class VI well rule. If this is the case, 

EPA will in effect reduce oil and gas production significantly during the 

existing server domestic energy shortage! Since operating conditions of CO2 EOR 

are different, e.g., Supercritical CO2 is not left in the reservoir at 

abandonment, and casing penetrating the cap-rock can be protected from 

corrosion, etc., the converting of CO2 EOR wells to Class VI wells is neither 

justified nor appropriate. 

Response: EPA clarifies that the GS rule does not change the requirements or address Class II EOR

operations. EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA believes that the nature and risks of CO2

injection for the primary purpose of long term storage poses different risks than injection for the

primary purpose of EOR, and therefore has developed new Class VI regulations to address these

unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is

significantly greater than for ER operations. Reservoir pressure conditions will also be different, with

Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II EOR projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary

purpose of long term storage obtain a Class VI permit with some special consideration for the fact

that they are transitioning from a well not originally designed to meet Class VI requirements. The
Director has the authority to determine at what point a Class VI permit is required for those projects

that are transitioning from the primary purpose of EOR to long term storage of CO2. The final

regulation provides a set of technical factors for the Director to evaluate in making this

determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs

when there is an increased risk to USDWs as compared to traditional Class II operations while

allowing for site-specific flexibility. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: Matt Toner Letter ID: 0117

Commenter Organization: Hydrogen Energy International Comment ID: 22061

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: STREAMLINING OF REQUIREMENTS 

Existing Class II regulations governing injection of CO2 in oil & gas reservoirs 

have proven successful at protecting USDWs and the health and safety of the 

public at large. These regulations should allow for the dual purpose of 

sequestration, if anthropogenic CO2 is used. 

Hydrogen Energy also recommends that EPA expand grandfathering to facilitate transition from

production and storage to storage-only sites, which will incentivize the use of these reservoirs for

long-term CO2 storage. 

Proposed grandfathering of Class II wells should go beyond just construction 

requirements to include, at a minimum, operating and mechanical integrity 

requirements for existing, operationally compliant, Class II EOR-CO2 injection 

wells. The Class VI requirements would require technically unnecessary changes 

to equipment and monitoring procedures. 

Some authors have identified leakage risk with using oil & gas reservoirs for 

CO2 sequestration due to the presence of inactive wells. Proper plugging and 

abandonment of inactive wells is a proven method which can ensure this risk is 

effectively managed. In addition, the oil and gas industry has developed 

techniques to quickly isolate, effectively repair and remediate these issues, in 

their unlikely occurrence. 

Response: As described above, the final GS rule provides for the construction of Class II wells to be

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

the wells were engineered and constructed to meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the well as Class VI, many

of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.
Commenter Name: Matt Toner Letter ID: 0117

Commenter Organization: Hydrogen Energy International Comment ID: 22063

Comment: Incentivizing the use of anthropogenic CO2 for enhanced oil or gas recovery 

would: 

-Significantly reduce CO2 emissions - Currently over 2 billion cubic feet of 

naturally-occurring CO2 is used for EOR in the US every day and volumes are 

growing; 

-Increase Energy security by facilitating additional EOR activity and thereby 

reducing the need for foreign oil 

-EOR has the potential to add 40-80 billion barrels of oil, based on estimates, which is 2 to 4 times

the current US total proved reserves; 

-Effectively utilize proven, well-studied and well-tested geologic storage 

containers - It will likely cost $10's of millions and take years of study to 

permit one commercial scale saline storage reservoir; 

-Effectively utilize over 100 years of oil field operating experience while 

building new competence for future saline storage options; 

-Effectively build on the successful regulatory framework for UIC Class II wells; 

and, finally, it would help kick-start the financially challenged carbon capture 

industry, by improving economics and accelerating uptake of this critical 

technology. 

Response: EPA clarifies that the purpose of the GS rule is not to incentivize or encourage the use of

GS, but to ensure that, where GS is deployed, it is conducted in a manner that does not endanger

USDWs. Furthermore, the purpose of the GS rule is not to incentivize the use of anthropogenic CO2

for EOR purposes.

Commenter Name: Doug Louis Letter ID: 0121

Commenter Organization: Kansas Corporation Commission Comment ID: 22074

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: Grandfathering Class II wells to Class VI wells. 

It is believed a great deal of potential storage of CO2 exists in EOR-CO2 floods 

after oil production ceases. It is my concern that EPA’s stringent standards for 

well cementing, monitoring and financial assurance will discourage oil operators 

using this additional pore space for sequestration, thus causing waste. If a 

CO2-EOR operation has successfully operated for many years, why should the 

standards be raised simply because it undergoes a well classification change? 

Response: Underground injection for the primary purpose of long term storage is sufficiently

different from Class II ER operations and warrants tailored requirements provided in the GS

rulemaking. For example, the volume of CO2 anticipated to be injected in Class VI wells is

significantly greater than for Class II wells. Reservoir pressure conditions will also be different, with
Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II ER projects. 

In response to the comment that ER operators will be discouraged from pursuing GS or using

additional pore space for storage, EPA clarifies that the purpose of the GS rule is not to incentivize

or encourage the use of GS or to address the use of pore space. The purpose of the GS rule is to

ensure that, where GS is deployed, it is conducted in a manner that does not endanger USDWs.

Furthermore, based on the administrative record, which includes the evaluation of available project

data, EPA believes that the Class VI requirements are not overly stringent and reflect the operation,

monitoring, and modeling currently conducted at several existing GS sites

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24742

Comment: The proposal does not seem to consider CO2 to be sequestered during injection 

for EOR. The first economic CO2 sequestration projects will be associated with 

oil and gas operations, yet the Proposal states that sequestration (and thus, 

Class VI injection) begins only after enhanced recovery of oil or gas has 

stopped. The implication is that the CO2 injected for enhanced recovery is not 

ultimately sequestered upon cessation of injection and production activity. The 

proposal grandfathers the construction of wells permitted as Class V and Class 

II, but requires that the wells comply with all other requirements of Class VI 

wells before injecting CO2 for sequestration. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of EOR, and that sites used for ER may be suitable for GS and may be among the first

GS sites. EPA also recognizes that a by-product of ER activities is that a certain percentage of the

CO2 is trapped in the receiving formation. However, EPA believes that injection for the primary

purpose of long term storage is sufficiently different from Class II ER operations and warrants

tailored requirements in order to protect USDWs from endangerment. For example, the volume of

CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells.

Reservoir pressure conditions will also be different, with Class VI injection operations involving

large volumes of CO2 and likely having higher pressures within their storage formations than Class

II EOR projects.

EPA clarifies that 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. For more information, please see the discussion on

transition of Class II wells in the preamble to the final GS rule.

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24744

Comment: 1. EPA should consider creating a subclass within the Class II well 
classification for operators who wish to sequester CO2 in association with 

enhanced recovery of oil or natural gas (with appropriate and necessary 

additional requirements to address any CO2 issues) and allow the Class VI 

injection well program to govern those injection wells used to sequester CO2 in 

formations that are non-productive. 

2. EPA should begin with a reasonable framework (Class II injection wells); 

assure that the rules are flexible enough to consider site-specific 

characteristics and knowledge gained from CO2 history and the ongoing 

demonstration and pilot projects; and that include performance-based 

requirements. Because of Texas’ and other States’ long experience with injection 

operations, the States are in an excellent position to perceive and act upon 

similarities in fluids injected, construction depth, design, operating 

techniques and purposes between its Class II and potential Class VI wells. 

Response: The Agency disagrees that wells injecting CO2 for the primary purpose of long term

storage should be regulated under Class II requirements or be classified as a sub-class of Class II

well classification. EPA recognizes that the oil and gas industry has decades of experience injecting

CO2 for the purpose of EOR, and that sites used for EOR may be suitable for GS and may be among

the first GS sites. EPA also recognizes that a by-product of EOR activities is that a certain

percentage of the CO2 is trapped in the receiving formation. 

However, the Agency believes that the nature and risks of CO2 injection for the primary purpose of

long term storage poses different risks than injection for the primary purpose of ER, and therefore

has developed new Class VI regulations to address these unique risks in order to protect USDWs

from endangerment. For example, the volume of CO2 anticipated to be injected for long term

storage is significantly greater than for EOR operations. Reservoir pressure conditions will also be

different, with Class VI injection operations involving large volumes of CO2 and likely having

higher pressures within their storage formations than Class II EOR projects. EPA believes that

injection of CO2 for the primary purpose of enhancing oil and gas recovery should remain under the

Class II Program. 

EPA has taken a regulatory approach which promotes USDW protection, incorporates flexibility or

the discretion of the permitting authority when appropriate, seeks to limit burden on owners or

operators and permitting agencies, and provides a foundation for national consistency in permitting

of GS projects. For example, under the final rule, many of the permit requirements must be

established through site-specific plans (e.g., AOR and corrective action plan, testing and monitoring

plan, etc.) developed by the owner or operator and approved by the Director. Consequently EPA

expects that owners or operators will consult with the Director as they develop, implement, and

update these plans. Additionally, the Director has the discretion to approve alternatives to the

requirements in some cases. For example, the Director may in certain situations modify the length of

the post-injection site care period or approve an alternative post-injection site care timeframe as part

of the permitting process under §146.93, allow the use of alternate methods for mechanical integrity

testing under §146.89, or grant waivers from the requirement to inject below the lowermost USDW

under §146.95.

Commenter Name: John Stormon Letter ID: 0123

Commenter Organization: Washington State Dept. of Ecology Comment ID: 22998

Other EPA Comment Codes and Descriptions: 1600 1.3 Risk Associated with CO2 GS 
Comment: Risk: Geologic Sequestration is not the same as Enhanced Oil Recovery (EOR) and 

needs to have much high standards than EOR activities have had to date. 

Protecting USDW is the most important aspect of the UIC program for the geologic 

sequestration of carbon dioxide. Although limited experience has been gained by 

the oil and gas industry injecting CO2 into proven structural traps for EOR, 

this experience has limited carry over to broader strategies for geologic 

sequestration. Geologic sequestration, unlike EOR, is being considered in basins 

without proven oil and gas capture and holding reservoirs. Even where exhausted 

oil and gas reservoirs are being considered for geologic sequestration, the 

amount of carbon dioxide to be injected is far greater than used for EOR and the 

goals of the injection are different. There is an unknown, likely large, level 

of risk associated with large geologic sequestration projects. The regulatory 

standards for site selection, site characterization and ongoing monitoring 

should be kept high to help ensure that the worst case scenarios are never 

realized. 

Response: EPA agrees that the nature and risks of CO2 injection for long-term storage are different

from Class II CO2 injection for ER, and that tailored requirements for GS wells are necessary to

protect USDWs from endangerment. For this reason, the Agency tailored UIC requirements for Class

VI wells that address the general risks deep injection may pose to USDWs and specifically address

the unique nature of CO2 GS (i.e., very large volumes, very long time-periods, and reservoir

pressure conditions). 

EPA recognizes that injecting large volumes of CO2 for GS poses unique challenges that, if not

properly managed, could endanger drinking water sources or have other adverse impacts. Although

EPA believes that a lot can be learned from the EOR experience, EPA agrees that caution is

warranted and has, as a result, developed a new well class with requirements tailored to address the

unique challenges posed by GS and potential risks associated with long-term injection of CO2. For

example, these requirements include the tailored AoR delineation process per §146.84, monitoring

that is appropriate to GS projects per §146.90, and extended post-injection site care per §146.93. 

As part of its adaptive rulemaking approach, the Agency plans, every six years, to collect and review

data on GS projects to determine whether the appropriate amount and types of information and

appropriate documentation are being collected, and to determine if modifications to the requirements

are appropriate or necessary.

Commenter Name: John Stormon Letter ID: 0123

Commenter Organization: Washington State Dept. of Ecology Comment ID: 22999

Comment: EOR: Keep a strong separation between the programs for EOR and geologic 

sequestration. EOR occurs in areas with oil reservoirs, with little 

contemplation to the site's long term storage and CO2 containment 

characteristics. Although some oil and gas reservoirs are likely to have very 

good potential as geologic sequestration sites, the determination of which 

reservoirs should be based upon excellent site characterization work that 

verifies that they will provide good long term geologic sequestration with few 

environmental risks. 

Response: As described above, EPA agrees that the nature and risks of CO2 injection for long-term

storage is different from Class II CO2 injection for ER, and that tailored requirements for GS wells
are appropriate and necessary to protect USDWs from endangerment. For this reason, the Agency

tailored UIC requirements for Class VI wells that address the general risks deep injection may pose

to USDWs and specifically address the unique nature of CO2 GS (i.e., very large volumes, very long

time-periods, and reservoir pressure conditions). EPA adds that the decision to permit GS at a given

site will be based on the suitability of that particular site, not on the type of geologic formation.

Furthermore, EPA clarifies that injection of carbon dioxide for the purpose of enhanced recovery is

regulated under Class II. 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.

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0127

Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 23966

Comment: 6. Class II Enhanced oil recovery CO2 injection wells reservoirs are produced 

until abandonment, which lower the pressure to about the original pressure, 

Unlike Class II wells, sequestration well will be abandoned at the maximum 

injection pressure. 

Response: EPA agrees that the nature and risks associated with CO2 injection for long term storage

are different from Class II CO2 injection for ER, and that tailored requirements for GS wells are

appropriate and necessary to protect USDWs from endangerment. For this reason, the Agency

tailored UIC requirements for Class VI wells that address the general risks deep injection may pose

to USDWs and specifically address the unique nature of CO2 GS (i.e., very large volumes, very long

time-periods, and reservoir pressure conditions). 

EPA adds that, while at the time that injection operations cease, pressures will be high (or at

maximum), owners or operators of Class VI wells will be required to perform extensive postinjection site care and monitoring until pressures decline to the point that USDWs are not

endangered as required under §146.93. See the discussion of post-injection site care in the preamble

to the final rule for additional information.

Commenter Name: Dawn A. Thorne Letter ID:

0134

Commenter Organization: University of Utah Energy and Geoscience Institute on

behalf of the Southwest Regional Partnership

Comment

ID: 21664

Comment: 4.) The SWP would like to comment on area permits and dual-purpose wells as 

they relate to commercial scale sequestration fields. 

The purpose of the proposed Class VI well is strictly for injection of CO2. The 

SWP would like to point out that for a commercial scale sequestration site there 

may be several injection wells that serve multiple purposes (i.e., injection of 

CO2, injection of brine, production of CO2 and production of brine). For 

example, one of the mitigation strategies for relieving pressure on an injection 

reservoir may be to produce either injected CO2 or displaced brine. As a form of 

"waste management", it may be desirable to re-inject the produced brine into 

another reservoir. In that case, a single well could serve as a CO2 injection 
well, brine disposal well, and production well. The SWP recommends that the EPA 

address the permitting requirements for both a large area (i.e., area permit) 

and dual-purpose wells in relation to geologic sequestration. 

Response: EPA disagrees that area permits are appropriate for GS projects or that dual-purpose

wells may be permitted as Class VI wells. 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. 

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

assist Directors in evaluating whether an injection project should transition 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 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.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141

Commenter Organization: Global Energy, Inc. Comment ID: 23102

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: 3.We highly recommend that EPA think in terms of the 80-20 rule of pragmatism 

when determining how to implement the conversion of an EOR well to a 

sequestration well. It is arguable that an EOR well is sufficiently relevant 

to a Class-6 well and has sufficient integrity to give it credit (at least 

partial credit) in the carbon injection and storage calculus. Reasonable 

mechanical retrofits may be appropriate, without having to replace casing, for 

example. 

In this we strongly support the EPA suggestion that EOR wells might be 

grandfathered when considering conversion to a GS well. Reasonable rework, 

though not reinstallation (or re- cementing, for example) might be decided on a 

case-by-case basis. That is, a single well, or a few wells, are not likely to 

materially affect USDW. 

Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a).

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 adds that, following re-permitting as Class VI wells, these

projects must be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection

site care and site closure requirements in the final GS rule.

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

assist Directors in evaluating 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 when determining 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.

Commenter Name: Patrick Nugent Letter ID: 0143

Commenter Organization: Texas Pipeline Association (TPA) Comment ID: 23123

Comment: 1. Development of a Class VI injection well program should not impair or 

any way modify existing authorizations for Class injection wells. 

As mentioned above, the oil and gas industry relies upon the authorization 

provided by the Class H injection well program for the disposal of acid or sour 

gas, enhanced oil recovery and as authorization for storage and retrieval of 

natural gas and other hydrocarbons. Carbon dioxide is often a part of the fluids 

that are brought to the surface in connection with conventional oil or natural 

gas production operations. It is, therefore, often a component of the acid gas 

stream that, in some cases, is injected for disposal -- effectively sequestering 

the carbon dioxide component of this stream. The sequestration of carbon dioxide 

in this situation is incidental to the primary activity, which is the disposal 

of acid gas. A distinction needs to be made in EPA's rules between the 

incidental sequestering of carbon dioxide in an acid gas disposal operation and 

an activity whose primary purpose is to sequester carbon dioxide under the new 

proposed Class VI authorization. TPA strongly urges EPA to ensure that the 

status quo for existing operations conducted under Class II injection well 

authorizations is protected and maintained. Elimination or modification of the 

Class II injection well program would have a severe economic impact on the oil 

and gas industry. TPA requests EPA to make an affirmative statement in the final 

rule that the following Class II wells are exempt from the applicability of 

Class VI wells requirements, unless applicability is requested by the owner or 

operator of the well: (1) those Class II wells that inject carbon dioxide and 

other fluids which are brought to the surface in connection with conventional 

oil or natural gas production operations; and (2) those Class II wells that 

inject carbon dioxide and other fluids which are operated in connection with an 

enhanced oil or gas recovery field. This express exemption would eliminate any 

confusion between the Class II and VI well programs that may arise should EPA 

remain silent on this issue. 
Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA recognizes that the oil and gas industry has

decades of experience injecting CO2 for the purpose of EOR, and that sites used for ER may be

suitable for GS and may be among the first GS sites. EPA also recognizes that a by-product of EOR

activities is that a certain percentage of the CO2 is trapped in the receiving formation.

The Agency believes that the nature and risks associated with CO2 injection for the primary purpose

of long term storage poses different risks than injection for the primary purpose of ER, and therefore

has developed new Class VI regulations to address these unique risks. For example, the volume of

CO2 anticipated to be injected for long term storage is significantly greater than for EOR operations.

Reservoir pressure conditions will also be different, with Class VI injection operations involving

large volumes of CO2 and likely having higher pressures within their storage formations than Class

II EOR projects. 

EPA clarifies that the GS rule does not “exempt” any specific activity from Class VI requirements,

but rather defines the tailored requirements that are necessary for the long-term storage of CO2 in

order to protect USDWs. 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 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 longterm storage of large volumes of CO2. The guidance describes the methods available for the Director

to use in order to determine 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.

Commenter Name: Jeff Moseley Letter ID: 0155

Commenter Organization: Greater Houston Partnership (GHP) Comment ID: 21256

Comment: 3. Recognize and maintain :he integrity of the existing Class II regulatory 

framework for CO2 EOR projects; 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA recognizes that the oil and gas industry has

decades of experience injecting CO2 for the purpose of ER, and that sites used for ER may be

suitable for GS and may be among the first GS sites. EPA also recognizes that a by-product of ER

activities is that a certain percentage of the CO2 is trapped in the receiving formation.

However, 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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: James Dooley Letter ID: 0156

Commenter Organization: Joint Global Change Research Institute, Pacific

Northwest National Laboratory

Comment ID:

22623

Comment: On Allowing Class II EOR and Class VI GS to Evolve on Parallel Tracks: An 

Example of the Challenge Inherent in "Filling in the Missing Linkages between 

Class VI Rule and a Larger National Climate Policy" 

The USEPA is to be commended for resisting numerous calls from a number of 

stakeholders to fit GS CO2 storage into the existing framework for CO2-driven 

enhanced oil recovery (EOR). It is critically important that all stakeholders 

understand that these are very different processes with distinct infrastructures 

and operating practices and which are driven by different economic motives. 

The fact that they both inject CO2 into the deep subsurface is not a sufficient 

reason to treat CO2-driven EOR and GS CO2 storage in the same regulatory manner 

(see page 43502, "Why is EPA Proposing to Develop a New Class of Injection Well 

for GS of CO2?" as well as the section on that same page (How Would this 

Proposal Affect Existing Injection Wells Under the UIC Program?) 

Page 43502. Again, the USEPA should be commended for critically thinking 

through the extent to which Class II EOR practices and future Class VI CO2 

storage are similar in practice. Allowing for the possibility of conversion of 

Class II wells into Class VI wells is a reasonable step to take which might, in 

a very limited number of instances in specific regions of the U.S., lower the 

cost of complying with the proposed Class VI rule. And the proposed Class VI 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature and risks associated with injecting large volumes of CO2 and to ensure that USDWs

are protected from endangerment. The GS rule contains tailored requirements for the permitting,

geologic site characterization, AoR and corrective action, well construction, operation, mechanical

integrity testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that

directly address issues unique to the nature of large-scale CO2 injection for GS. 

EPA also agrees that the risks posed by long term storage of CO2 for GS cannot be addressed under

existing UIC requirements, such as those for Class II wells. EPA believes that there are significant

differences between how projects are operated, as well as the risks posed by these different injection

activities. The new tailored approach of the GS rule was designed to address the general risks deep

injection may pose to USDWs and was tailored specifically to address the risks posed by long term

storage of CO2 (i.e., very large volumes, very long time-periods, and reservoir pressure conditions).

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: James Childress Letter ID: 0158

Commenter Organization: Gasification Technologies Council (GTC) Comment ID: 23765

Comment: Concern #10: Continuation of Class II for EOR. (Ref: page 43502, Sec. G) 

By proposing different and more restrictive requirements for Class VI wells, EPA 

will create economic or operational barriers that prevent a seamless transition 

from EOR and storage operations to wholly storage operations. EOR can make a 

significant contribution to offset the cost of early CCS demonstration projects. 

For example, EOR can contribute to the investment in pipeline infrastructure 

helping to enable pure CCS operations. Also, CO2 storage operations may continue 

after EOR has ceased, thus reducing the cost of storage, site characterization 

and development. These benefits should be viewed as especially significant in 

light of the difficulties in securing sufficient funds to initially deploy CCS. 

EOR projects could quite feasibly bring CCS deployment forward by many years as 

a considerable quantity of CO2 remains underground during such operations. This 

will reduce the number of target formations where CO2 could be stored. 

Response: In response to the comment that establishing a new well class will create economic and

operational barriers, EPA clarifies that the purpose of the GS rule is to ensure protection of USDWs

from endangerment. The Agency believes that establishing a regulatory framework for the future

development and deployment of CCS technology may provide the regulatory and jurisdictional

certainty needed to foster development and deployment of CCS while ensuring USDW protection.

However, this is not the purpose of the rule and the comment is outside the scope of the rulemaking. 

Regarding the comment that Class VI requirements will reduce the number of available target

formations where CO2 can be stored, EPA reiterates that the regulation is meant to ensure that

proposed sites are suitable for safely injecting, and confining CO2, and avoid sites not suited for GS.

EPA notes the final GS rule contains a provision at §146.95 for owners or operators the ability to

apply for waivers from the requirement that injection takes place below the lowermost USDW. EPA

believes this waiver provision will reduce potential limitations on the re-permitting of Class II wells

as Class VI wells, provided they meet the requirements at §146.95 while still protecting USDWs

from endangerment.

Commenter Name: M. Michael Rounds Letter ID: 0159

Commenter Organization: Midwestern Governors Association (MGA) Comment ID: 22227

Comment: Enhanced oil recovery projects Essential components of a comprehensive 

greenhouse reduction strategy for the Midwest include the opportunity for 

current and future properly managed CO2-EOR projects to make the transition to, 
and to be permitted as, long-term sequestration projects for anthropogenic CO2 

under EPA’s proposed Class VI. Therefore, in order to fully utilize EOR sites as 

part of such a strategy, it will be important for EPA’s proposed rule to make 

certain that CO2-EOR will continue uninterrupted and to provide CO2-EOR 

operators a clear, workable path for Class II wells used for CO2-EOR to become 

Class VI wells. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA recognizes that the oil and gas industry has

decades of experience injecting CO2 for the purpose of EOR, and that sites used for EOR may be

suitable for GS and may be among the first GS sites. The Agency believes that the nature and risks

of CO2 injection for the primary purpose of long term storage poses different risks than injection for

the primary purpose of ER, and therefore has developed new Class VI regulations to address these

unique risks.

EPA agrees that many Class II wells are designed and constructed to withstand exposure to CO2.

The final GS rule allows the construction of these wells to be grandfathered per §146.81(c), provided

the owner or operator can demonstrate to the Director that the wells were engineered and constructed

to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at

§146.86(b) and §146.87(a).

EPA 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 longterm storage of large volumes of CO2. The guidance describes the methods available for the Director

to evaulate changes in risk to USDWs from projects, and recommended approaches for 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.

Commenter Name: M. Michael Rounds Letter ID: 0159

Commenter Organization: Midwestern Governors Association (MGA) Comment ID: 22229

Comment: More generally, we urge that EPA take great care to avoid creating barriers to 

widespread commercial development of responsible CO2-EOR projects that make the 

transition to long-term sequestration. EOR is a necessary element of our 

strategy to develop a regional infrastructure to support commercial-scale 

deployment of CCS in the Midwestern region. Indeed, in some MGA jurisdictions 

with significant sequestration potential in oil and gas formations, EOR 

represents a major long-term GHG reduction strategy in its own right, as well as 

a bridge to help finance the infrastructure needed for deep saline aquifer 

sequestration. The EOR industry has significant, longstanding commercial 

experience in CO2 injection, and some MGA states have proven regulatory 

experience in managing CO2 injection EOR projects, including projects using 

captured CO2 that deliver net CO2 reduction benefits, even after accounting for 

oil recovered. The Midwest needs a supportive federal regulatory environment to 

be able to leverage this experience to develop projects and to build the 

infrastructure necessary for the transport and injection of CO2 into depleted 

oil and gas fields. 
Response: EPA believes that injection of CO2 for the primary purpose of enhancing oil and gas

recovery must remain under the Class II Program. EPA also recognizes that the oil and gas industry

has decades of experience injecting CO2 for the purpose of ER, and that sites used for ER may be

suitable for GS and may be among the first GS sites. However, EPA believes that injection for the

primary purpose of long term storage is sufficiently different from Class II ER operations and

warrants tailored requirements. For example, the volume of CO2 anticipated to be injected in Class

VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will also be

different, with Class VI injection operations involving large volumes of CO2 and likely having

higher pressures within their storage formations than Class II ER projects.

In response to the comment that establishing a new well class will create economic and operational

barriers, EPA clarifies that the purpose of the GS rule is to ensure protection of USDWs from

endangerment, not to encourage and incentivize deployment of GS. However, the Agency believes

that establishing a regulatory framework for the future development and deployment of CCS

technology may provide the regulatory and jurisdictional certainty needed to foster development and

deployment of CCS while ensuring USDW protection.

Commenter Name: Sandi Tabor Letter ID: 0162

Commenter Organization: Lignite Energy Council (LEC) Comment ID: 21298

Comment: flexibility within the regulation of the new class. We agree that where there is 

an EOR component in a project, the project should continue to be permitted and 

regulated under the Class II program. For that matter, we also support granting 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA also recognizes that the oil and gas

industry has decades of experience injecting CO2 for the purpose of EOR, and that sites used for

EOR may be suitable for GS and may be among the first GS sites. However, EPA believes that

injection for the primary purpose of long term storage is sufficiently different from Class II EOR

operations and warrants tailored requirements. For example, the volume of CO2 anticipated to be

injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure

conditions will also be different, with Class VI injection operations involving large volumes of CO2

and likely having higher pressures within their storage formations than Class II EOR projects.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23405

Comment: grandfathering of Class I, II and V for the Class VI as storage sites. APPA 

cannot easily imagine why an oil and gas production field would typically want 

to move from a Class II to a Class VI well classification since oil and gas 

recovery is always technically possible at the right price. Besides, UIC Class 

II production classification has certain other regulatory and commercial 

advantages to remain as Class II to the oil and gas sector. Few wells are truly 

ever 100% depleted since newer technology may make unreachable oil and gas 

obtainable. APPA does not oppose state directors who believe that they should 

grandfather a well from Class II to a Class VI provided that it can be 

demonstrated to the state’s satisfaction that such carrying over of requirements 

will be protective of USDWs. 
Response: EPA believes that injection for the primary purpose of long term storage is sufficiently

different from Class II ER operations and warrants tailored requirements in order to protect USDWs

from endangerment. For example, the volume of CO2 anticipated to be injected in Class VI wells is

significantly greater than for Class II wells. Reservoir pressure conditions will also be different, with

Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II ER projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary

purpose of long term storage obtain a Class VI permit with some special consideration for the fact

that they are transitioning from a well not originally designed to meet Class VI requirements. The

Director has the authority to determine at what point a Class VI permit is required for those projects

that are transitioning from the primary purpose of EOR to long term storage of CO2. The final

regulation provides a set of technical factors for the Director to evaluate in making this

determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs

when there is an increased risk to USDWs as compared to traditional Class II operations while

allowing for site-specific flexibility. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

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 longterm storage of large volumes of CO2. The guidance describes the methods available for the Director

to evaluate changes in risk to USDWs from projects, and recommended approaches the Director may

use to evaluate 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.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24128

Comment: Differentiating Applicability of Class II versus Class VI Permits 

API supports the concept embodied in the preamble that injection of CO2 for the 

purposes of enhanced oil and gas recovery in producing wells, even if production 

ceases for a period, will continue to be permitted under the Class II program 

(73 FR 43502). API would like to see EPA remain committed to the intent of the 

language in the preamble and EPA's interpretation of that language as expressed 

during API's meeting with EPA on October 27th ,that CO2 storage in association 

with EOR activities proceeds under the Class II program. 

As mentioned earlier, this is an area that has been discussed by the MSDG. The 

Group proposes a "bright line" for distinguishing Class II EOR "business as 

usual" from other activities (see §146.5(b){4)). API proposes that wells used 

for GS in oil and gas reservoirs that do not meet the criteria proposed for 

§144.6{b)(4) be regulated under the Class II program since it would facilitate 

EOR operations transitioning to GS under the same regulatory jurisdiction. 

The approach is not radically different from the approach proposed by EPA (as 

amended by API) for transitioning from EOR to Geologic Storage (see comments 

regarding §146.81(c) in API's line-by line edits to the proposed rule). Even if 
EPA's final decision is to establish a new well subclass under the Class II 

program, API's comments on the proposed Class VI rule remain relevant and should 

be addressed by EPA. 

Again, details of what would be required of wells used for GS in oil and gas 

reservoirs that do not meet the criteria proposed for §144.6(b){4) are to be 

worked out during future discussions of the Multi-Stakeholder Discussion Group 

(MSDG). However, API offers language which is consistent with suggestions API 

had developed before discussions with the MSDG began (see API's comments on 

§146.25). 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA recognizes that the oil and gas industry has

decades of experience injecting CO2 for the purpose of EOR, and that sites used for ER may be

suitable for GS and may be among the first GS sites. 

However, the Agency disagrees that wells injecting CO2 for the primary purpose of long-term

storage should be regulated under Class II requirements. The Agency believes that the nature and

risks of CO2 injection for the primary purpose of long-term storage pose different risks than

injection for the primary purpose of ER, and therefore has developed new Class VI regulations to

address these unique risks. For example, the volume of CO2 anticipated to be injected for long-term

storage is significantly greater than for ER operations. Reservoir pressure conditions will also be

different, with Class VI injection operations involving large volumes of CO2 and likely having

higher pressures within their storage formations than Class II ER projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary

purpose of long term storage obtain a Class VI permit with some special consideration for the fact

that they are transitioning from a well not originally designed to meet Class VI requirements. The

Director has the authority to determine at what point a Class VI permit is required for those projects

that are transitioning from the primary purpose of EOR to long term storage of CO2. The final

regulation provides a set of technical factors for the Director to evaluate in making this

determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs

when there is an increased risk to USDWs as compared to traditional Class II operations while

allowing for site-specific flexibility. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24133

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: [In this document, the text in all 

CAPS denotes added text. For redline strikeout version of this attachment see 

PDF Docket ID EPA-HQ-OW-2008-0390-0170.] 

Rule Provision: 144.3 

API Comments: ENHANCED OIL RECOVERY (EOR) OR ENHANCED GAS RECOVERY

(EGR) MEANS 

ANY ACTIVITY THAT USES FLUIDS, GASES OR OTHER MEANS TO IMPROVE OR

INCREASE 
EXTRACTION OF HYDROCARBONS. 

Rationale: The definition of EOR is necessary to support further comments and 

discussion below. 

Response: EPA included the following definition for Enhanced Oil or Gas Recovery in the

preamble to the rule: typically, the process of injecting a fluid (e.g., water, brine, or CO2) into an oil

or gas bearing formation to recover residual oil or natural gas. The injected fluid thins (decreases the

viscosity) and/or displaces small amounts of extractable oil and gas, which is then available for

recovery. This is also known as secondary or tertiary recovery.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24134

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 4400

2.4.4.3 Allowing injection above or between USDWs (seeking comment) 

Comment: Rule Provision: 144.6 

API Comments: Sections 144.6 - Classification of Wells: 

(b) Class II. Wells which inject fluids:... 

(4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC

SEQUESTRATION IS 

OCCURRING DURING OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR

NATURAL GAS 

PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE THAN INSIGNIFICANT

FUTURE 

PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION

AND (II) 

OPERATING PRESSURES ARE NO HIGHER THAN REASONABLY NECESSARY TO

PRODUCE SUCH 

VOLUMES OR RATES; AND 

(5) FOR GEOLOGIC SEQUESTRATION IN OIL AND GAS FORMATIONS AND WHERE THE

CRITERIA 

OF PARAGRAPH (B)(4) ARE NOT MET 

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon 

dioxide STREAMS. beneath the lowermost formation containing a USDW WELLS 

WHERE GEOLOGIC SEQUESTRATION OF CO2 STREAMS OCCURS DURING OR IN

CONNECTION WITH 

EOR OR EGR ARE REGULATED UNDER CLASS II. 

Rationale: Additionally, there should not be a blanket prohibition concerning 

injection above USDW’s or at specific depths. This is especially true given the 

possibility of changes in the definition of a USDW to include formations greater 

than 10,000 parts per million Total Dissolved Solids. This requirement is not 

necessary for the protection of USDWs and would remove a vast number of viable 

formations from consideration. Industry has shown that it can operate CO2 

injection wells in an EOR context without endangering USDWs that are located 

below the injection zone. An excellent example is the Salt Creek EOR project in 
Wyoming, which has a USDW below the injection zone. Moreover, under the proposed 

rule, there are other measures that would provide real assurance of formation 

integrity and require operators to demonstrate that their project will not 

endanger USDWs, making the lowermost USDW restriction unnecessary. 

Response: EPA did not make the suggested change. EPA clarifies that the final rule requires that

injection for GS be into non-USDWs below the lowermost USDW; however, owners or operators

may apply for a waiver from this requirement, as described in §146.95. For more information, see

the discussion of waivers in the preamble to the final rule.

The Agency disagrees that wells injecting CO2 for the primary purpose of long-term storage should

be regulated under Class II requirements. The Agency believes that the nature and risks of CO2

injection for the primary purpose of long-term storage pose different risks than injection for the

primary purpose of ER, and therefore has developed new Class VI regulations to address these

unique risks. For example, the volume of CO2 anticipated to be injected for long-term storage is

significantly greater than for ER operations. Reservoir pressure conditions will also be different, with

Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II ER projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary

purpose of long term storage obtain a Class VI permit with some special consideration for the fact

that they are transitioning from a well not originally designed to meet Class VI requirements. The

Director has the authority to determine at what point a Class VI permit is required for those projects

that are transitioning from the primary purpose of EOR to long term storage of CO2. The final

regulation provides a set of technical factors for the Director to evaluate in making this

determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs

when there is an increased risk to USDWs as compared to traditional Class II operations while

allowing for site-specific flexibility. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

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 longterm storage of large volumes of CO2. The guidance describes the recommended methods the

Director may use to determine 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.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24137

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 4324

2.4.4.1.2 Comments opposed to requiring injection below the lowermost USDW 

Comment: Rule Provision: 144.80 

API Comments: b) Class II. Wells which inject fluids:...... (4) FOR ENHANCED 

RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC SEQUESTRATION IS

OCCURRING DURING 

OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR NATURAL GAS
PROVIDED (I) THERE 

IS REASONABLE EXPECTATION OF MORE THAN INSIGNIFICANT FUTURE

PRODUCTION VOLUMES 

OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION AND (II) OPERATING

PRESSURES 

ARE NO HIGHER THAN REASONABLY NECESSARY TO PRODUCE SUCH VOLUMES OR

RATES; AND 

(5) FOR GEOLOGIC SEQUESTRATION IN OIL AND GAS FORMATIONS AND WHERE THE

CRITERIA 

OF PARAGRAPH (B)(4) ARE NOT MET 

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon 

dioxide STREAMS. WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2 STREAMS

OCCURS DURING 

OR IN CONNECTION WITH EOR OR EGR ARE REGULATED UNDER CLASS II. 

Rationale: See 144.6 

Response: As described above regarding the suggested edit at 144.6, EPA did not make the

suggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of longterm storage should be regulated under Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24138

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 4324

2.4.4.1.2 Comments opposed to requiring injection below the lowermost USDW 

Comment: Rule Provision: 146.5 

API Comments: b) Class II. Wells which inject fluids:...... (4) FOR ENHANCED 

RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC SEQUESTRATION IS

OCCURRING DURING 

OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR NATURAL GAS

PROVIDED (I) THERE 

IS REASONABLE EXPECTATION OF MORE THAN INSIGNIFICANT FUTURE

PRODUCTION VOLUMES 

OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION AND (II) OPERATING

PRESSURES 

ARE NO HIGHER THAN REASONABLY NECESSARY TO PRODUCE SUCH VOLUMES OR

RATES; AND 

(5) FOR GEOLOGIC SEQUESTRATION IN OIL AND GAS FORMATIONS AND WHERE THE

CRITERIA 

OF PARAGRAPH (B)(4) ARE NOT MET 
(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon 

dioxide STREAMS. Beneath the lowermost formation containing an underground 

source of drinking water (USDW). WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2 

STREAMS OCCURS DURING OR IN CONNECTION WITH EOR OR EGR ARE REGULATED

UNDER CLASS 

II. 

Rationale: See 144.6 

Response: As described above regarding the suggested edit at 144.6, EPA did not make the

suggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of longterm storage should be regulated under Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

EPA clarifies that the final rule requires that injection for GS be into non-USDWs below the

lowermost USDW; however, owners or operators may apply for a waiver from this requirement, as

described in §146.95. For more information, see the discussion of waivers in the preamble to the

final rule.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs from endangerment, as long as appropriate

protections are in place. However, EPA disagrees with the suggested addition to the regulation. The

final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver of the

Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. It establishes: 1) requirements specifying information that owners or operators

must submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for

public notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class

VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. 

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24140

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: API Comments: (b) This subpart applies to wells used to inject carbon dioxide 

EXCLUSIVELY for the purpose of geologic sequestration, i.e., the long-term 

containment of a gaseous, liquid or supercritical carbon dioxide stream in 

subsurface geologic formations. IT IS RECOGNIZED THAT SOME ACTIVITIES CONDUCTED 

UNDER CLASS II, INCLUDING CO2 BASED EOR OR EGR MAY SEQUESTER A PORTION

OF THE 

CARBON DIOXIDE STREAM USED FOR EOR OR EGR. THIS SUBPART DOES NOT APPLY

TO 

INJECTION OF A CARBON DIOXIDE STREAM FOR PURPOSES OF EOR OR EGR EVEN

THOUGH 

GEOLOGIC SEQUESTRATION OF CARBON DIOXIDE MAY OCCUR DURING OR IN
CONNECTION WITH 

EOR OR EGR OPERATIONS AND/OR ACTIVITIES. 

Rationale: See 144.6. Deleted "gaseous, liquid or supercritical" because it was 

added to the definition of CO2 stream. 

Response: As described above regarding the suggested edit at 144.6, EPA did not make the

suggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of longterm storage should be regulated under Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24141

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.81(c) 

API Comments: (c) This subpart applies to owners and operators of permit or 

rule-authorized Class I industrial, Class II, or Class V experimental carbon 

dioxide injection projects who seek to apply for a Class VI geologic 

sequestration permit for their well or wells. If the Director determines that 

USDWs will not be endangered, such wells are exempt, at the Director‘s 

discretion, from the casing and cementing requirements at §§ 146.86(b) and 

146.87(a)(1) through (3). 

Rationale: The reference to Class II wells in section 146.81(c) is no longer 

needed due to addition of 146.25 . However, if EPA were not to adopt section 

146.25, API would suggest the following revisions: 

(c) This subpart applies to owners and operators of permit or rule-authorized 

Class I industrial, Class II WHO HAVE CEASED AND WILL NO LONGER CONTINUE EOR OR

EGR OPERATIONS OR ACTIVITIES, or Class V experimental carbon dioxide injection 

projects who seek to apply for a Class VI geologic sequestration permit for 

their well or wells. If the Director determines that USDWs will not be 

endangered, such wells are exempt, at the Director‘s discretion, from the 

casing and cementing requirements at §§ 146.86(b) and 146.87(a)(1) through 

(3). CLASS VI REQUIREMENTS. CLASS II WELLS PERMITTED FOR CO2 INJECTION AND 

THAT HAVE DEMONSTRATED MIT ARE EXEMPT FROM THE REQUIREMENTS AT

§§146.86 AND 

146.87. 

The language allows for the transition of Class II wells to Class VI operations. 

These wells should be allowed to inject CO2 for storage based on their history 

of sound performance under the Class II program as demonstrated by MIT results. 

The language also allows the Director to exercise discretion to exempt other 
Class VI requirements. 

Response: As described above, EPA disagrees that wells injecting CO2 for the primary purpose of

long-term storage should be regulated under Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24214

Comment: EPA Preamble Question: 2. Injection of CO2 for the purposes of enhanced oil and 

gas recovery (EOR/EGR), as long as any production is occurring, will continue to 

be permitted under the Class II program. EPA seeks comment on the merits of this 

approach since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted. EPA Notice 43502. 

API Response: API strongly supports the absence of an economic test for oil and 

gas reservoir "depletion." API contends that EOR needs to be maintained under 

the current Class II program and supports EPA’s proposal that any storage that 

occurs under EOR continues to be handled under the Class II program. 

Additionally, API supports the creation of a subclass under Class II (e.g "Class 

IIB") for storage operations in hydrocarbon formations after EOR activities. See 

API’s proposed section 146.25. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA recognizes that the oil and gas industry has

decades of experience injecting CO2 for the purpose of ER, and that sites used for ER may be

suitable for GS and may be among the first GS sites. 

However, the Agency disagrees that wells injecting CO2 for the primary purpose of long-term

storage should be regulated under Class II requirements (e.g., the Class IIB category suggested by

the commenter). The Agency believes that the nature and risks of CO2 injection for the primary

purpose of long-term storage poses different risks than injection for the primary purpose of ER, and

therefore has developed new Class VI regulations to address these unique risks. For example, the

volume of CO2 anticipated to be injected for long term storage is significantly greater than for ER

operations. Reservoir pressure conditions will also be different, with Class VI injection operations

involving large volumes of CO2 and likely having higher pressures within their storage formations

than Class II ER projects. 

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 longterm storage of large volumes of CO2. The guidance describes the methods available for the Director

to evaluate changes in risk to USDWs from projects, and recommended approaches the Director may

use to evaluate 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.

Commenter Name: Pamela Faggert Letter ID: 0175

Commenter Organization: Dominion Comment ID: 23528

Comment: 6. Transitioning Existing Permitted Wells 

The Final Rule should recognize that EOR and EGR wells are the most likely to be 

utilized for GS by early adopters of commercial sequestration. 

The Agency should facilitate the use of existing EOR/EGR wells for 

purposes of GS, provided that they ensure adequate protection of USDW. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for EOR may be among the first GS sites. EPA also agrees

that many Class II wells are designed and constructed to withstand exposure to CO2. The final GS

rule allows the construction of these wells to be grandfathered per §146.81(c), provided the owner or

operator can demonstrate to the Director that the wells were engineered and constructed to meet the

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

and §146.87(a).

EPA 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 longterm storage of large volumes of CO2. The guidance describes the methods available for the Director

to evaluate changes in risk to USDWs from projects, and recommended approaches the Director may

use to evaluate 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.

Commenter Name: Kenneth Nemeth Letter ID: 0176

Commenter Organization: Southern States Energy Board Comment ID: 23547

Comment: It is not useful to arbitrarily limit the depth of coal seams, since coal seams 

store CO2 via a very different mechanism such that the required pressures are 

only a few hundred pounds per square inch (psi) instead of many hundreds or 

thousands of psi. The Southeast contains numerous oil and gas fields that are 

potential safe geologic storage sites. SSEB encourages EPA to adopt a reasonable 

process for EOR sequestration within Class II and EOR crossover to sequestration 

in oil and gas fields. Oil and gas fields are proven geologic sinks and contain 

much of the needed infrastructure for efficient sequestration. 

Response: Regarding injection into coal seams, EPA agrees that the GS rule should not categorically

preclude or prohibit injection into any type of non-USDW formation. EPA also acknowledges that

there are limited circumstances where injection above the lowermost USDW can be performed in a

manner that protects USDWs. The final GS rule at 146.95 establishes a process by which owners or

operators can seek a waiver of the Class VI injection depth requirements. The waiver approach

requires the submission of extensive, site-specific information (in conjunction with the permit

application submittal) to demonstrate that injection of CO2 into a formation that is above or between
USDWs can be done in a manner that protects USDWs from endangerment. The requirements are

designed to ensure the owner or operator, the Director, and the Regional Administrator consider, on

a site specific basis, the implications, benefits, and challenges associated with GS and ensuring water

availability and USDW protection. 

Regarding use of oil and gas fields for GS, EPA believes that the nature and risks of CO2 injection

for long term storage is different from Class II CO2 injection for ER, and that tailored requirements

for GS wells are appropriate and necessary to protect USDWs from endangerment. For this reason,

the Agency tailored UIC requirements for Class VI wells that address the general risks deep injection

may pose to USDWs and specifically address the unique nature of CO2 GS (i.e., very large volumes,

very long time-periods, and reservoir pressure conditions). 

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 longterm storage of large volumes of CO2. The guidance describes the methods available for the Director

to evaluate changes in risk to USDWs from projects, and recommended approaches the Director may

use to evaluate 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.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23811

Comment: technology".[FN6] The CCS Alliance agrees that where there is an EOR component 

in a project, that project should continue to be permitted and regulated under 

the Class II program. It is also positive that EPA is proposing that Directors 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA also recognizes that the oil and gas

industry has decades of experience injecting CO2 for the purpose of ER, and that sites used for ER

may be suitable for GS and may be among the first GS sites. 

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: Lee O. Fuller Letter ID: 0179

Commenter Organization: Independent Petroleum Association of America et

al.

Comment ID:

23611

Comment: First, EPA properly notes that CO2 is used for EOR. The Department of Energy 
studied the potential for extended use of CO2 and reported that at least six oil 

producing basins were potential EOR areas and that over 100 billion barrels of 

American oil could potentially be produced utilizing this technology 

(Undeveloped Domestic Oil Resources: The Foundation For Increased Oil Production 

And A Viable Domestic Oil Industry, February 2006). In fact, when CO2 EOR is 

used, a significant portion of the CO2 remains in the oil reservoir and 

effectively becomes geologically sequestered. With recognition of the goals of 

sequestration, those volumes will dramatically grow. At issue is whether the 

Class VI proposal would interfere with the EOR projects. We strongly urge EPA to 

assure that CO2 EOR and its attendant sequestration are not inhibited by the 

application of Class VI requirements to EOR operations. EPA recognizes that the 

Class VI requirements should not be applied to Class II CO2 EOR operations. We 

believe that the current process of shutting down oil field operations (site 

closure) effectively protects the environment under existing regulatory 

structure and do not support changes that would discourage EOR activities by 

imposing new requirements at the end of the reservoir’s life. Such requirements 

would effectively discourage CO2 EOR and result in less American oil production 

and less geologic sequestration of CO2. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. However, EPA believes that the nature and risks

of CO2 injection for long term storage is different from Class II CO2 injection for ER, and that

tailored requirements for GS wells are appropriate and necessary to protect USDWs from

endangerment. For this reason, the Agency tailored UIC requirements for Class VI wells that address

the general risks deep injection may pose to USDWs and specifically address the unique nature of

CO2 GS (i.e., very large volumes, very long time-periods, and reservoir pressure conditions. 

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 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 longterm storage of large volumes of CO2. The guidance describes the 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.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23683
Comment: Category: Grandfathering Wells/ Enhanced Oil Recovery Wells 

EPA Request for Comment: Injection of CO2 for the purposes of enhanced oil and 

gas recovery (EOR/EGR), as long as any production is occurring, will continue to 

be permitted under the Class II program. EPA seeks comment on the merits of this 

approach since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted. EPA Notice 43502. 

AWWA Response: AWWA agrees with this approach and supports the continued 

operation of Class II wells for EOR/EGR as long as they are still producing. 

However, AWWA recommends that an economic test for oil and gas reservoir 

"depletion" be used to determine when the Class II well should be transitioned 

to Class VI, and then operated under the Class VI conditions. One suggestion for 

determining when the reservoir has been depleted is to determine what the lowest 

physical amount of production would be. When oil or gas production reaches this 

point, the owner or operator would be required to plug the production wells and 

begin the application process for converting the remaining injection wells to 

Class VI wells. EPA needs to monitor the operation of existing Class II wells to 

ensure that they are not being operated as carbon sequestration projects, as 

there are significant differences in the permitting and operation of these two 

classes. Companies will try to bypass some of the Class VI construction 

requirements by designing and operating the system as an EOR/EGR project for a 

few years, and then converting it to a geologic sequestration system. 

Response: EPA agrees that the nature and risks of CO2 injection for long term storage is different

from Class II CO2 injection for EOR, and that tailored requirements for GS wells are appropriate and

necessary to protect USDWs from endangerment. For this reason, the Agency tailored UIC

requirements for Class VI wells that address the general risks deep injection may pose to USDWs

and specifically address the unique nature of CO2 GS (i.e., very large volumes, very long timeperiods, and reservoir pressure conditions). 

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 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 longterm storage of large volumes of CO2. The guidance describes the 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.
Commenter Name: Adam P. Haynes Letter ID: 0184

Commenter Organization: Texas Independent Producers and Royalty Owners

Association (TIPRO)

Comment ID:

22786

Comment: Related to that point, enhanced oil and gas recovery (EOR & EGR) must be a 

component of any successful carbon capture and storage (CCS) regulatory system. 

While the proposed rule does not preclude enhanced recovery of hydrocarbons, the 

lack of attention to this process is troubling. As mentioned, the exploration 

and production sector has been successfully using geologic storage of CO2 for 

more than 30 years. The EPA should promote EOR and EGR as a proven mechanism for 

CCS and allow for it through the use of properly permitted Class II wells 

located throughout the country. Rather than developing a new category of 

injection wells as the new Class VI wells are contemplated in the rules, EPA 

should allow Class II wells to continue to be the standard for CCS projects 

going forward. If there is a need to differentiate between commercial storage 

projects and enhanced recovery projects - and TIPRO does not believe such a need 

exists - then the EPA needs to create two separate categories for Class II 

wells. One category can be used in non-hydrocarbon injection zones when storage 

is for commercial purposes only. The other category of Class II wells can be 

used by the exploration and production sector during EOR and EGR projects. Of 

course, the rule changes also need to address the transition of well bores in 

between the two categories. Once an enhanced recovery process is complete, the 

existing formation presents a beneficial target formation for the commercial 

storage of CO2, The transition from one category of Class II well to the other 

should not involve any downhole modifications or retrofits. Rather, the process 

of transitioning between classifications should be contingent on the applicant 

completing a mechanical integrity test that demonstrates protection of the USDW 

and other applicable surface controls necessary to ensure storage and capture 

rates. 

Response: EPA believes that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA disagrees that the risks posed by long term

storage of CO2 for GS can be addressed under existing UIC requirements in order to protect

USDWs from endangerment, such as those for Class II wells. EPA believes that there are significant

differences between how projects are operated, as well as the risks posed by these different injection

activities. The new tailored approach of the GS rule was designed to address the general risks deep

injection may pose to USDWs and was tailored specifically to address the risks posed by long term

storage of CO2 (i.e., very large volumes, very long time-periods, and reservoir pressure conditions).

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 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 longterm 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.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25172

Comment: B. EPA seeks comment on the merits of this approach since owners or operators of 

some Class II EOR/EGR wells may wish to use wells for the purposes of production 

and GS prior to the field being completely depleted. 

NYSDEC-DMN Response: NYSDEC-DMN agrees with EPA’s proposed approach provided the 

project is an EOR project under Class II and the operator is able to demonstrate 

it as an ongoing viable EOR project. Operators should not be allowed to inject 

and store CO2 under the guise of a Class II EOR project to avoid Class VI 

permitting requirements. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA agrees that the nature and risks of CO2

injection for long term storage is different from Class II CO2 injection for ER, and that tailored

requirements for GS wells are appropriate and necessary to protect USDWs from endangerment. For

this reason, the Agency tailored UIC requirements for Class VI wells that address the general risks

deep injection may pose to USDWs and specifically address the unique nature of CO2 GS (i.e., very

large volumes, very long time-periods, and reservoir pressure conditions). 

EPA agrees and clarifies that 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 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 longterm 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.
Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24320

Comment: B. We Support Continued Application of the Class II Regulations to CO2 Injection 

in the Enhanced Oil or Gas Recovery Context and for GS in Oil and Gas Reservoirs 

and the Creation of "Class VI" Regulations to Address Most Other CO2 Injection 

Wells Used for GS. 

CO2 injection wells are currently permitted as Class II or Class V "experimental 

technology" wells. Under the proposed rule, Class II CO2 injection in 

conjunction with oil and gas production would remain under Class II, and a new 

classification - Class VI - would be created for GS. This approach makes sense 

except that all injection of CO2 in oil and gas reservoirs, including injection 

for GS, should remain in Class II to avoid circumstances where EOR operations 

might be compelled to shift back and forth between Class II and Class VI 

depending on market conditions. CO2 injection for purposes of enhanced oil or 

gas recovery ("EOR/EGR") has been successfully regulated as Class II injection 

for decades, and we agree with EPA that there is nothing to justify any 

disruption of the existing regulatory regime for the thousands of injection 

wells already in use in these operations. For other GS injection projects 

outside of oil and gas reservoirs, Class VI regulations would permit a more 

structured basis for regulation than the current Class V regulations. 

As EPA has recognized, the creation of a new well class does raise some 

applicability and transition issues. The key applicability issue relates to the 

distinction between Class II and Class VI when CO2 is injected for the purpose 

of GS in connection with EOR/EGR operations. EPA’s Proposal would continue to 

regulate and permit injection of CO2 for EOR/EGR purposes as Class II injection 

"as long as any production is occurring." EPA has asked for comment on the 

merits of this approach "since owners or operators of some Class II EOR/EGR 

wells may wish to use wells for the purposes of production and GS prior to the 

field being completely depleted." 73 Fed. Reg. at 43502. In fact, it is more 

than likely that CO2 will be injected both for purposes of EOR/EGR and GS. The 

rules should be clarified to be consistent with EPA’s intent, as we understand 

it, that where GS of CO2 occurs in connection with EOR/EGR activities the 

applicable class of wells and regulatory requirements is Class II. Furthermore, 

the UIC rules should provide a "bright line" standard for determining when 

EOR/EGR production activities cease and CO2 injection for GS continues. When 

EOR/EGR production activities cease and CO2 injection for purpose of GS 

continues, the risk profile changes, as further discussed below. This potential 

change in risk profile would necessitate additional requirements that are 

commensurate with both the historic EOR/EGR operations in the particular oil and 

gas field and with the risk profile of continued CO2 injection for GS. The MSD 

joint letter states that the Group has agreed that the wells used for GS in oil 

and gas reservoirs that do not meet the criteria of (b)(4) should be subject to 

additional requirements" and indicates further that the Group has "tentatively 

defined such wells as wells used ‘for geologic sequestration in oil and gas 

formations and where the criteria of paragraph (b)(4) are not met.’" There may 

be a further recommendation that EPA establish a Class II regulatory regime for 

continued injection of CO2 for GS when EOR/EGR production has been terminated 

based upon a "bright line" definition. These topics are discussed in further 
detail below. 

In the course of a typical EOR operation, even where there is no intent to 

sequester, 30-50% of the injected CO2 will remain in the reservoir after 

production operations cease. The balance is either dissolved within the produced 

oil or recycled for use in other reservoirs; it is not emitted to the 

atmosphere. Today approximately 90% of the CO2 used in enhanced recovery 

operations is produced from naturally occurring geologic accumulations. Rather 

than using this naturally occurring CO2, operators should be encouraged to 

mitigate greenhouse gas emissions by using anthropogenic CO2 instead. Oil and 

gas reservoirs have proved capable of containing water-buoyant fluids and gases 

for millions of years. These reservoirs are well studied and they offer the best 

opportunity to kick-start large-scale geologic storage of CO2 building on 100 

years of oil field operating experience. Accordingly, EOR/EGR operations using 

the same procedures now in place would result in sequestering anthropogenic CO2 

and should continue to be subject to the same requirements that have 

successfully protected USDWs since the inception of enhanced recovery 

operations. EPA should therefore clarify that EOR/EGR operations that include 

CO2 injection for the purpose of sequestration, or what is sometimes called "EOR 

with sequestration," will remain covered by Class II requirements. EPA 

recognition of EOR with anthropogenic CO2 as a valid form of geologic 

sequestration will provide much needed incentive for near-term geologic 

sequestration efforts, while longer-term cap and trade or taxation schemes 

develop. As long as oil or gas production continues, this remains an EOR/EGR 

operation and should remain in Class II. 

There are two different transition issues; the first of which involves the 

status of Class II CO2 injection wells after oil and gas recovery operations 

cease. In this situation, EPA should revise its proposal to retain the 

regulation of all GS in oil and gas reservoirs in Class II, subject to 

appropriate requirements as discussed below. Rather than require such wells to 

be permitted as Class VI wells - often by regulators in a different state agency 

than that authorized to administer the Class II program - this approach would 

leave permitting in the hands of the regulators with existing knowledge and 

expertise with respect to the oil and gas reservoirs and injection wells 

involved, thus leveraging regulatory resources and facilitating the seamless 

transition of oil and gas reservoirs to GS service following the completion of 

EOR/EGR operations. This approach would also reduce administrative complications 

or jurisdictional complexities that might otherwise arise and would provide 

additional regulatory flexibility in situations where production may stop and 

start in response to changing market conditions. 

Response: The Agency disagrees that wells injecting CO2 for the primary purpose of long-term

storage should be regulated under Class II requirements and has therefore developed new Class VI

regulations to address the unique challenges and risks posed by this injection activity. The Agency

tailored UIC requirements for Class VI wells that address the general risks deep injection may pose

to USDWs and specifically address the unique nature of CO2 GS (i.e., very large volumes, very long

time-periods, and reservoir pressure conditions). 

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 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 longterm 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.

In response to the comment on the burden of changing regulatory agencies in the middle of an

operation, EPA clarifies that primacy is granted to a state, not to a specific agency within that state,

and states may choose which agency will implement the Class VI program. States may, for example,

choose an environmental quality protection agency (non-Class II) or the state's traditional oil and gas

regulatory agency to implement the Class VI program as long as the program meets the minimum

federal requirements for Class VI wells as required under section 1422 of SDWA. Some states

manage all injection well classes under Section 1422 and through a single agency, while in other

states, Class II programs are run by oil and gas agencies. Some States allow their oil and gas

agencies to regulate other well classes or subclasses provided they meet all federal requirements and

are approved by the Agency.

Regardless of the specific Agency the state selects to assume regulatory authority for Class VI

operations, the state must obtain primacy for the 1422 Class VI program. Furthermore, the state may

determine that a memorandum of understanding (MOU) between several state agencies regarding

specific projects can facilitate this process without needing to change regulatory agencies after Class

II projects have transitioned to a Class VI permit.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24321

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: The other transition issue involves the substantive requirements that should 

apply to existing, currently-permitted wells that are converted to GS service. 

The preamble indicates that "the owner or operator would need to follow the 

permitting process outlined in today’s proposal to receive a Class VI permit," 

but EPA proposes "to give the Director discretion to carry over or ‘grandfather’ 

the construction requirements for existing wells if the Director makes a 

determination "that these wells would not endanger USDWs." 73 Fed. Reg. at 

43502. This approach seems backwards: having recognized the problems associated 

with the application of new well construction standards to existing wells, EPA 
should recognize that the well construction standards for all well classes are 

designed to ensure that USDWs are not endangered. Consequently, in the absence 

of some specific evidence of a construction problem that might endanger a USDW, 

there is no basis to question the construction of an existing, previouslypermitted injection well, and any "grandfathering" with respect to the Class VI 

construction requirements should be virtually automatic. 

In addition, it is important to recognize that the need and justification for 

"grandfathering" is not limited to construction requirements. There are also 

proposed Class VI operational and monitoring requirements that would require the 

substantial modification - if not outright abandonment - of many existing CO2 

injection wells (the proposed requirement for continuous monitoring of annulus 

pressure is a conspicuous example). In every case, the wells at issue have 

already been constructed consistent with requirements that UIC program officials 

have determined to be sufficient to prevent endangerment of USDWs. In view of 

this fact, there should be a regulatory presumption - absent some specific 

information to the contrary - that continued operation of wells already in CO2 

service for CO2 injection will also be protective of USDWs. 

The proposed Class VI regulations would require a relatively elaborate 

demonstration that injected CO2 will remain isolated from USDWs, and some 

supplementation of the permit requirements for existing wells may be appropriate 

consistent with the broad geological containment standards for Class VI wells. 

To the extent these or other supplemental requirements are truly necessary, they 

could and should be imposed through modification or supplementation of existing 

permit conditions rather than through the wholesale application of Class VI 

program requirements to pre-existing activities already found to be protective 

of USDWs. Accordingly, we recommend that the Final Rule include a presumption 

that wells already in CO2 service be allowed to transition to Class VI status-- 

or, in the case of Class II wells, to remain in Class II and be used for 

GS-based on their existing permit conditions, subject only to additional 

requirements as necessary to demonstrate geologic containment of the injected 

CO2 stream. 

Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. Furthermore, the final GS rule allows the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered from Class II wells. Following re-permitting of the well

as Class VI, many of the unique factors of GS sites (e.g., increased reservoir pressures associated

with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water) will result in

an increased risk profile, warranting the specific requirements in the final GS rule. Therefore,

following re-permitting as Class VI wells, these projects would be subject to the operational, MIT,

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final

GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for

additional detail on these requirements.
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 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 longterm storage of large volumes of CO2. The guidance describes the 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24361

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: Rule Provision: 144.6(b) 

Proposed CCS Group Recommendations: Add new paragraph (b)(4) 

(4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC

SEQUESTRATION IS 

OCCURRING DURING OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR

NATURAL GAS 

PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE THAN INSIGNIFICANT

FUTURE 

PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION

AND (II) 

OPERATING PRESSURES ARE NO HIGHER THAN REASONABLY NECESSARY TO

PRODUCE SUCH 

VOLUMES OR RATES; 

Basis for CCS Group Comments: EPA’s Proposal would continue to regulate and 

permit injection of CO2 for EOR/EGR purposes as Class II injection "as long as 

any production is occurring." EPA has asked for comment on the merits of this 

approach "since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted." 73 Fed. Reg. at 43502. We recommend that the rules be 

clarified to provide more certainty about the applicability of Class II 

requirements where GS of CO2 occurs in connection with EOR/EGR activities. 

Specifically, the UIC rules should provide a "bright line" definition as to the 

applicable class of wells where CO2 injection for EOR/EGR production and for GS 
occur in tandem. 

The proposed language describing wells in classification (b)(4) establishes a 

"bright line" definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the 

current requirements of Class II. We have also agreed that the wells used for GS 

in oil and gas reservoirs that do not meet the criteria of (b)(4) should be 

subject to additional requirements. 

This is the same recommendation as presented by the multi-stakeholder group, in 

which the Carbon Sequestration Council participated. 

Response: EPA did not make the suggested change. The Agency disagrees that wells injecting CO2

for the primary purpose of long-term storage should be regulated under Class II requirements. The

Agency believes that the nature and risks of CO2 injection for the primary purpose of long-term

storage pose different risks than injection for the primary purpose of EOR, and therefore has

developed new Class VI regulations to address these unique risks. For example, the volume of CO2

anticipated to be injected for long-term storage is significantly greater than for EOR operations.

Reservoir pressure conditions will also be different, with Class VI injection operations involving

large volumes of CO2 and likely having higher pressures within their storage formations than Class

II EOR projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary

purpose of long term storage obtain a Class VI permit with some special consideration for the fact

that they are transitioning from a well not originally designed to meet Class VI requirements. The

Director has the authority to determine at what point a Class VI permit is required for those projects

that are transitioning from the primary purpose of EOR to long term storage of CO2. The final

regulation provides a set of technical factors for the Director to evaluate in making this

determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs

when there is an increased risk to USDWs as compared to traditional Class II operations while

allowing for site-specific flexibility. 

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 longterm storage of large volumes of CO2. The guidance describes the 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24362

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: Rule Provision: 144.6(f) 

Proposed CCS Group Recommendations: (f) Class VI. used for geologic 

sequestration of carbon dioxide beneath the lowermost formation containing a 
USDW. Wells INJECTING A CARBON DIOXIDE STREAM FOR GEOLOGIC

SEQUESTRATION 

EXCEPT THOSE WELLS DESCRIBED IN SUBSECTION (B)(4) OF THIS SECTION OR

OTHERWISE 

EXCLUDED FROM THIS CLASS. 

Basis for CCS Group Comments: The changes to (b) and (f) are to recognize that 

EOR can have a storage component, which is consistent with EPA’s intent as 

expressed in the preamble. It is widely recognized that CO2 based EOR can 

provide a significant early opportunity for carbon storage. As EPA correctly 

recognizes, CO2 EOR operations can have a significant storage component through 

capillary trapping or other mechanisms. Operators experience supports this 

approach as they have seen that between 1/3 to 1/2 of the injected CO2 in EOR 

operations is trapped within the receiving formation during CO2 EOR operations. 

Following abandonment of EOR operations, assuming the CO2 not trapped in the 

receiving formation, has not been produced for use in another field, essentially 

all of the CO2 that has been injected can be permanently stored. 

We recommend that all GS into basalts, coal seams, and salt domes be conducted 

under Class V as experimental wells initially and then as commercial scale Class 

V wells/projects if the experimental projects demonstrate that these sites can 

be suitable for geological sequestration while preventing endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain enough 

experience to develop suitable permitting requirements for such wells and to 

tailor those requirements at both the pilot and commercial scales until the 

agencies are ready to adapt the Class VI regulations. 

There should not be a blanket prohibition concerning injection above USDW’s or 

at specific depths. This requirement is not necessary for the protection of 

USDWs and would remove a vast number of viable formations from consideration. It 

has been shown that it is possible to operate CO2 injection wells in an EOR 

context without endangering USDWs that are located below the injection zone. An 

excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Under the proposed rule, there are other measures that 

would provide real assurance of formation integrity and require operators to 

demonstrate that their project will not endanger USDWs, making the lowermost 

USDW restriction unnecessary. Instead, operators should be able to show adequate 

containment to prevent endangerment of USDWs both above and below the injection 

zone used for geologic sequestration. 

Response: As described above regarding the suggested edit at 144.6(b), EPA did not make the

suggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of longterm storage should be regulated under Class II requirements.

Regarding injection into basalts, coal seams, and salt domes, EPA clarifies that the GS rule does not

categorically preclude injection of CO2 into any non-USDW formation types. The purpose of the GS

rule is to ensure protection of USDWs from endangerment, and the rule requires that owners or

operators demonstrate that wells are sited in suitable systems with geologic formations to receive

and confine injected CO2, as required at §146.83 of the GS rule. The Class VI siting, well
construction and operation, monitoring and testing, and post-injection site care and site closure

requirements are designed to ensure that injected CO2 remains within the target formation. If an

owner or operator can demonstrate to the Director's satisfaction that GS in coal seams, basalts, salt

domes, or shales can be accomplished in a manner that protects USDWs and meets all of the

requirements of the GS rule, the project may be permitted as a Class VI well. 

EPA acknowledges that there may be unknown risks associated with GS, particularly regarding GS

into formations such as coal seams, basalts, and salt domes, which have been the subject of limited

experimental projects in the past. EPA anticipates that in the short-term, GS into these types of

formations will continue to be experimental (i.e., if they are to test GS technologies and collect data),

and will likely be permitted as Class V experimental technology wells and be subject to UIC

Program Guidance #83. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to Class VI projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs. The final GS rule at §146.95 establishes a

process by which owners or operators can seek a waiver of the Class VI injection depth

requirements. The waiver approach requires the submission of extensive, site-specific information

(in conjunction with the permit application submittal) to demonstrate that injection of CO2 into a

formation that is above or between USDWs can be done in a manner that is protective of USDWs.

The requirements are designed to ensure the owner or operator, the Director, and the Regional

Administrator consider, on a site-specific basis, the implications, benefits, and challenges associated

with GS and ensuring water availability and USDW protection.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24370

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 144.39 

Proposed CCS Group Recommendations: THESE SECTIONS MAY REQUIRE FURTHER

REVISIONS 

TO PROVIDE CONFORMING LANGUAGE. 

Basis for CCS Group Comments: The multi-stakeholder group has agreed that 

proposed language describing wells in classification (b)(4) establishes a 

"bright line" definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the 

current requirements of Class II. We have also agreed that the wells used for GS 

in oil and gas reservoirs that do not meet the criteria of (b)(4) should be 

subject to additional requirements. We have tentatively defined such wells as 

wells used "for geologic sequestration in oil and gas formations and where the 

criteria of paragraph (b)(4) are not met." But we have not yet attempted to 

define what specific requirements should apply to these wells. We are committed 

to working toward agreement on those requirements (probably within a Class II 
context) and submitting the results of that effort to EPA by February 28, 2009 

for your consideration. 

In addition, we recommend that all GS into basalts, coal seams, and salt domes 

be conducted under Class V as experimental wells initially and then as 

commercial scale Class V wells/projects if the experimental projects demonstrate 

that these sites can be suitable for geological sequestration while preventing 

endangerment of USDWs. 

Response: As described above, EPA agrees that injection of CO2 for the primary purpose of

enhancing oil and gas recovery should remain under the Class II Program. However, the Agency

disagrees that wells injecting CO2 for the primary purpose of long-term storage should be regulated

under Class II requirements. EPA recognizes that the oil and gas industry has decades of experience

injecting CO2 for the purpose of EOR, and that sites used for EOR may be suitable for GS and may

be among the first GS sites. EPA also recognizes that a by-product of EOR activities is that a certain

percentage of the CO2 is trapped in the receiving formation. 

The Agency believes that the nature and risks of CO2 injection for the primary purpose of long-term

storage pose different risks than injection for the primary purpose of ER, and therefore has

developed new Class VI regulations to address these unique risks. For example, the volume of CO2

anticipated to be injected for long-term storage is significantly greater than for EOR operations.

Reservoir pressure conditions will also be different, with Class VI injection operations involving

large volumes of CO2 and likely having higher pressures within their storage formations than Class

II EOR projects. 

As described above, EPA clarifies that the GS rule does not categorically preclude injection of CO2

into any non-USDW formation types. If an owner or operator can demonstrate to the Director's

satisfaction that GS in coal seams, basalts, salt domes, or shales can be accomplished in a manner

that protects USDWs and meets all of the requirements of the GS rule, the project may be permitted

as a Class VI well. 

The Agency anticipates that, in the near-term, most GS in unmineable coal seams will continue to be

experimental. Such projects may be permitted as Class V experimental technology wells if they are

of an experimental nature (i.e., to test GS technologies and collect data). EPA will continue to

review data on early GS projects, including those in unmineable coal seams, to determine whether

the appropriate amount and types of information and documentation are required and being

collected. EPA plans, every six years, to collect and review data on GS projects to determine whether

the appropriate amount and types of information and appropriate documentation are being collected,

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

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24380

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 144.80 

Proposed CCS Group Recommendations: (b) Class II. Classification of Wells: (b) 

Class II. Wells which inject fluids:.......(2) for enhanced recovery of oil or 

natural gas; (3) For storage of hydrocarbons.... and 
(4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC

SEQUESTRATION IS 

OCCURRING DURING OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR

NATURAL GAS 

PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE THAN INSIGNIFICANT

FUTURE 

PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION

AND (II) 

OPERATING PRESSURES ARE NO HIGHER THAN REASONABLY NECESSARY TO

PRODUCE SUCH 

VOLUMES OR RATES; 

Basis for CCS Group Comments: EPA’s Proposal would continue to regulate and 

permit injection of CO2 for EOR/EGR purposes as Class II injection "as long as 

any production is occurring." EPA has asked for comment on the merits of this 

approach "since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted." 73 Fed. Reg. at 43502. We recommend that the rules be 

clarified to provide more certainty about the applicability of Class II 

requirements where GS of CO2 occurs in connection with EOR/EGR activities. 

Specifically, the UIC rules should provide a "bright line" definition as to the 

applicable class of wells where CO2 injection for EOR/EGR production and for GS 

occur in tandem. 

The proposed language describing wells in classification (b)(4) establishes a 

"bright line" definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the 

current requirements of Class II. We have also agreed that the wells used for GS 

in oil and gas reservoirs that do not meet the criteria of (b)(4) should be 

subject to additional requirements. 

This is the same recommendation as presented by the multi-stakeholder group, in 

which the Carbon Sequestration Council participated. 

Response: As described above regarding the suggested edit at 144.6, EPA did not make the

suggested change to 144.80. The Agency disagrees that wells injecting CO2 for the primary purpose

of long-term storage should be regulated under Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24384

Comment: Basis for CCS Group Comments: The changes to (b) and (f) are to recognize that 

EOR can have a storage component, which is consistent with EPA’s intent as 

expressed in the preamble. It is widely recognized that CO2 based EOR can 

provide a significant early opportunity for carbon storage. As EPA correctly 
recognizes, CO2 EOR operations can have a significant storage component through 

capillary trapping or other mechanisms. Operators experience supports this 

approach as they have seen that between 1/3 to 1/2 of the injected CO2 in EOR 

operations is trapped within the receiving formation during CO2 EOR operations. 

Following abandonment of EOR operations, assuming the CO2 not trapped in the 

receiving formation, has not been produced for use in another field, essentially 

all of the CO2 that has been injected can be permanently stored. 

Response: As described above, EPA did not make the suggested change to 144.80. The Agency

disagrees that wells injecting CO2 for the primary purpose of long-term storage should be regulated

under Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24388

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.5(f) 

Proposed CCS Group Recommendations: (b) Class II. Classification of Wells: (b) 

Class II. Wells which inject fluids:.......(2) for enhanced recovery of oil or 

natural gas; (3) For storage of hydrocarbons..... and 

(4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC

SEQUESTRATION IS 

OCCURRING DURING OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR

NATURAL GAS 

PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE THAN INSIGNIFICANT

FUTURE 

PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION

AND (II) 

OPERATING PRESSURES ARE NO HIGHER THAN REASONABLY NECESSARY TO

PRODUCE SUCH 

VOLUMES OR RATES; 

Basis for CCS Group Comments: EPA’s Proposal would continue to regulate and 

permit injection of CO2 for EOR/EGR purposes as Class II injection "as long as 

any production is occurring." EPA has asked for comment on the merits of this 

approach "since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted." 73 Fed. Reg. at 43502. We recommend that the rules be 

clarified to provide more certainty about the applicability of Class II 

requirements where GS of CO2 occurs in connection with EOR/EGR activities. 

Specifically, the UIC rules should provide a "bright line" definition as to the 

applicable class of wells where CO2 injection for EOR/EGR production and for GS 

occur in tandem. 
The proposed language describing wells in classification (b)(4) establishes a 

"bright line" definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the 

Response: As described above, EPA did not make the suggested change. The Agency disagrees that

wells injecting CO2 for the primary purpose of long-term storage should be regulated under Class II

requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

The Agency believes that the nature and risks of CO2 injection for the primary purpose of long-term

storage pose different risks than injection for the primary purpose of ER, and therefore has

developed new Class VI regulations to address these unique risks. For example, the volume of CO2

anticipated to be injected for long-term storage is significantly greater than for ER operations.

Reservoir pressure conditions will also be different, with Class VI injection operations involving

large volumes of CO2 and likely having higher pressures within their storage formations than Class

II ER projects.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24391

Comment: Basis for CCS Group Comments: The changes to (b) and (f) are to recognize that 

EOR can have a storage component, which is consistent with EPA’s intent as 

expressed in the preamble. It is widely recognized that CO2 based EOR can 

provide a significant early opportunity for carbon storage. As EPA correctly 

recognizes, CO2 EOR operations can have a significant storage component through 

capillary trapping or other mechanisms. Operators experience supports this 

approach as they have seen that between 1/3 to 1/2 of the injected CO2 in EOR 

operations is trapped within the receiving formation during CO2 EOR operations. 

Following abandonment of EOR operations, assuming the CO2 not trapped in the 

receiving formation, has not been produced for use in another field, essentially 

all of the CO2 that has been injected can be permanently stored. 

Response: As described above regarding the suggested edit at 144.6, EPA did not make the

suggested change. The Agency acknowledge that some CO2 stays trapped in the formation, but

disagrees that wells injecting CO2 for the primary purpose of long-term storage should be regulated

under Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24396

Comment: Basis for CCS Group Comments: The multi-stakeholder group has agreed that 

proposed language describing wells in classification (b)(4) establishes a 
"bright line" definition for wells that inject CO2 for EOR/EGR and GS and, 

consistent with EPA’s intent, should remain in Class II and be subject to the 

current requirements of Class II. We have also agreed that the wells used for GS 

in oil and gas reservoirs that do not meet the criteria of (b)(4) should be 

subject to additional requirements. We have tentatively defined such wells as 

wells used "for geologic sequestration in oil and gas formations and where the 

criteria of paragraph (b)(4) are not met." But we have not yet attempted to 

define what specific requirements should apply to these wells. We are committed 

to working toward agreement on those requirements (probably within a Class II 

context) and submitting the results of that effort to EPA by February 28, 2009 

for your consideration. 

Response: As described above, EPA believes that injection for the primary purpose of long-term

storage is sufficiently different from Class II ER operations and warrants tailored requirements. For

example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than

for Class II wells. Reservoir pressure conditions will also be different, with Class VI injection

operations involving large volumes of CO2 and likely having higher pressures within their storage

formations than Class II ER projects. 

EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas recovery should

remain under the Class II Program. EPA believes that there are significant differences between how

projects are operated, as well as the risks posed by these different injection activities. The new

tailored approach of the GS rule was designed to address the general risks deep injection may pose to

USDWs and was tailored specifically to address the risks posed by long-term storage of CO2 (i.e.,

very large volumes, very long time-periods, and reservoir pressure conditions).

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 longterm storage of large volumes of CO2. The guidance describes the 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24507

Comment: Rule Provisions or Federal Register Cite: 73 FR 43502 

EPA Preamble Question: 2. Injection of CO2 for the purposes of enhanced oil and 

gas recovery (EOR/EGR), as long as any production is occurring, will continue to 

be permitted under the Class II program. EPA seeks comment on the merits of this 

approach since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted. EPA Notice 43502. 

CSC Response: EOR needs to be maintained under the current Class II program and 

any storage that occurs under EOR should continue to be handled under the Class 

II program. CSC supports the language developed by the multi-stakeholder 
discussion (MSD) group that would make this more explicit. 

We also support the absence of an economic test for oil and gas reservoir 

"depletion." The MSD group has developed language for differentiating between 

wells in oil and gas reservoirs that should be permitted under the current Class 

II program requirements and those that should be permitted under other 

provisions (preferably as Class II wells subject to enhanced requirements). 

Response: 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.

Commenter Name: Kyle Isakower Letter ID: 0191

Commenter Organization: American Petroleum Institute Comment ID: 23878

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Enhanced recovery of oil or natural gas and geologic sequestration of CO2 

EPA’s Proposal would continue to regulate and permit injection of CO2 for 

EOR/EGR purposes as Class II injection "as long as any production is occurring." 

EPA has asked for comment on the merits of this approach "since owners or 

operators of some Class II EOR/EGR wells may wish to use wells for the purposes 

of production and GS prior to the field being completely depleted." 73 Fed. Reg. 

at 43502. We recommend that the rules be clarified to provide more certainty 

about the applicability of Class II requirements where GS of CO2 occurs in 

connection with EOR/EGR activities. Specifically, the UIC rules should provide a 

"bright line" definition as to the applicable class of wells where CO2 injection 

for EOR/EGR production and for GS occur in tandem. We recommend the following 

language to accomplish that objective: 

[In the paragraphs below, the text in all CAPS denotes added text.] 

§ 144.6, 144.80 and 146.5, and Classification of injection wells. 

Injection wells are classified as follows: 

* * * 

(b) Class II. Wells which inject fluids: 

(1) Which are brought to the surface in connection with conventional oil 

or natural gas production and may be commingled with waste waters from 

gas plants which are an integral part of production operations, unless 
those waters are classified as a hazardous waste at the time of 

injection. 

(2) For enhanced recovery of oil or natural gas; 

(3) For storage of hydrocarbons which are liquid at standard temperature 

and pressure; 

(4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC 

SEQUESTRATION IS OCCURRING DURING OR IN CONNECTION WITH ENHANCED 

RECOVERY OF OIL OR NATURAL GAS PROVIDED (I) THERE IS REASONABLE 

EXPECTATION OF MORE THAN INSIGNIFICANT FUTURE PRODUCTION VOLUMES OR 

RATES AS A RESULT OF CARBON DIOXIDE INJECTION AND (II) OPERATING 

PRESSURES ARE NO HIGHER THAN REASONABLY NECESSARY TO PRODUCE SUCH 

VOLUMES OR RATES; 

* * * 

(F) CLASS VI. WELLS INJECTING A CARBON DIOXIDE STREAM FOR GEOLOGIC 

SEQUESTRATION EXCEPT THOSE WELLS DESCRIBED IN SUBSECTION (B)(4) OF THIS 

SECTION OR OTHERWISE EXCLUDED FROM THIS CLASS.[FN1/] 

[FN1/: Please note that well classification for geologic sequestration in 

certain formations is a matter still under discussion within the multistakeholder group and may be addressed further in future recommendations from 

the group. In the mean time individual participants in these discussions will be 

expressing views on this and other issues with an openness to revising their 

views if a consensus can be reached.] 

The undersigned have agreed that proposed language describing wells in 

classification (b)(4) establishes a "bright line" definition for wells that 

inject CO2 for EOR/EGR and GS and, consistent with EPA’s intent, should remain 

in Class II and be subject to the current requirements of Class II. We have also 

agreed that the wells used for GS in oil and gas reservoirs that do not meet the 

criteria of (b)(4) should be subject to additional requirements. We have 

tentatively defined such wells as wells used "for geologic sequestration in oil 

and gas formations and where the criteria of paragraph (b)(4) are not met." But 

we have not yet attempted to define what specific requirements should apply to 

these wells. We are committed to working toward agreement on those requirements 

(probably within a Class II context) and submitting the results of that effort 

to EPA by February 28, 2009 for your consideration. 

Response: EPA did not make the suggested change. The Agency disagrees that wells injecting CO2

for the primary purpose of long term storage should be regulated under Class II requirements. The

Agency believes that the nature and risks of CO2 injection for the primary purpose of long term

storage poses different risks than injection for the primary purpose of EOR, and therefore has

developed new Class VI regulations to address these unique risks. For example, the volume of CO2

anticipated to be injected for long term storage is significantly greater than for EOR operations.

Reservoir pressure conditions will also be different, with Class VI injection operations involving

large volumes of CO2 and likely having higher pressures within their storage formations than Class
II EOR projects.

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

Commenter Name: Jeff W. Sheets Letter ID: 0192

Commenter Organization: ConocoPhillips Comment ID: 23891

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Enhanced recovery of oil or natural gas and geologic sequestration of CO2 

EPA's Proposal would continue to regulate and permit injection of CO2 for 

EOR/EGR (enhanced gas recovery) purposes as Class II injection "as long as any 

production is occurring." EPA has asked for comment on the merits of this 

approach "since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted." 73 Fed. Reg. at 43502. We support the Multi-Stakeholder 

consensus recommendation that the rules be clarified to provide more certainty 

about the applicability of Class II requirements where GS of C02 occurs in 

connection with EOR/EGR activities. Specifically, the UIC rules should provide a 

"bright line" definition as to the applicable class of wells where C02 

injections for EOR/EGR production and for GS occur in tandem. We strongly 

support the recommendation for the following language to accomplish that 

objective: 

§ 144.6, 144.80 and 146.5, and Classification of injection wells. 

Injection wells are classified as follows: 

*** 

(b) Class II. Wells which inject fluids: 

(1) Which are brought to the surface in connection with conventional oil 

or natural gas production and may be commingled with waste waters from 

gas plants which are an integral part of production operations, unless 

those waters are classified as a hazardous waste at the time of 

injection. 

(2) For enhanced recovery of oil or natural gas; 

(3) For storage of hydrocarbons which are liquid at standard temperature 

and pressure; 

(4) For enhanced recovery of oil or natural gas where geologic 

sequestration is occurring during or in connection with enhanced 

recovery of oil or natural gas provided (i) there is reasonable 

expectation of more than insignificant future production volumes or 

rates as a result of carbon dioxide injection and (ii) operating 
pressures are no higher than reasonably necessary to produce such 

volumes or rates; 

* * * 

(f) Class VI. Wells injecting a carbon dioxide stream for geologic 

sequestration except those wells described in subsection (b)(4) of this 

section or otherwise excluded from this Class. 

The Multi-Stakeholder group has agreed that wells in classification (b)(4) 

should remain in Class II and be subject to the current requirements of Class 

II. We have also agreed that the wells used for GS in oil and gas reservoirs 

that do not meet the criteria of (b)(4) should be subject to additional 

requirements. We have tentatively defined such wells as wells used "for geologic 

sequestration in oil and gas formations and where the criteria of paragraph (b) 

(4) are not met" But we have not yet reached consensus on defining what specific 

requirements should apply to these wells. We are committed to working toward 

agreement on those requirements (probably within a Class II context) and 

submitting the results of that effort to EPA by February 28, 2009 for your 

consideration. 

ConocoPhillips further recommends that Class VI be used for wells designed 

"exclusively for geologic sequestration of carbon dioxide." This clarifies and 

broadens Class II to include former producing oil and gas wells, EOR wells, EOR 

with simultaneous storage, and EOR fields transitioning to/from storage, such 

that all oil and gas fields storing CO2 are Class II, whether producing or not. 

This approach removes uncertainty for fields which may have become storage 

fields, but return to production as economic conditions change, or cease 

production for some time as part of enhancing recovery, and possibly other 

scenarios. This approach acknowledges the track record of CO2 injection for EOR 

and the significant knowledge base in oil and gas fields. Thus, Class VI 

requirements would acknowledge the greater uncertainties inherent in often 

deeper saline storage, newer field developments, and possibly less defined 

closure structures. This approach also may safely accelerate CCS projects 

utilizing well known oil and gas formations, public acceptance may be more 

likely and regulatory authorities/ oil and gas agencies are in place to begin 

CCS projects. We support API's recommendation to add a Class II (b)(S), "For 

geologic sequestration in oil and gas formations and where the criteria of 

paragraph (b)(4) are not met". 

Response: EPA did not make the suggested change. The Agency disagrees that wells injecting CO2

for the primary purpose of long term storage should be regulated under Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

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 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.

Commenter Name: John R. Baza Letter ID: 0193

Commenter Organization: Utah Division of Oil, Gas, and Mining Comment ID: 23909

Comment: Enhanced Oil Recovery ("EOR") and EOR Crossover 

Injection into reservoirs for EOR should remain unchanged and regulated under 

the Class II program. In the case where an operator of an EOR would also choose 

to use their wells for the purpose of GS the wells should still be regulated 

under the Class II program. Additionally injection into non-producing oil and 

gas reservoirs should also remain under the Class II program. Injection into 

non-oil and non-gas reservoirs should appropriately fall into the newly proposed 

Class VI well category for GS as proposed. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. However, EPA believes that injection for the

primary purpose of long-term storage is sufficiently different from Class II ER operations and

warrants tailored requirements. For example, the volume of CO2 anticipated to be injected in Class

VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will also be

different, with Class VI injection operations involving large volumes of CO2 and likely having

higher pressures within their storage formations than Class II ER projects. EPA believes that there

are significant differences between how projects are operated, as well as the risks posed by these

different injection activities. The new tailored approach of the GS rule was designed to address the

general risks deep injection may pose to USDWs and was tailored specifically to address the risks

posed by long-term storage of CO2 (i.e., very large volumes, very long time-periods, and reservoir

pressure conditions).

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 longterm storage of large volumes of CO2. The guidance describes the 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.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24565

Comment: Injection Well Class (Class II vs. Class VI): 

Anadarko was very pleased to see the EPA maintain the integrity of the Class II 

program by excluding injection operations for the purpose of enhanced recovery. 
Also, Anadarko is in full support of developing two classes of wells to better 

address the associated risks with sequestration. By creating a Class II-B for 

the exclusive purpose of sequestration in oil and gas bearing formations, many 

of the complications with grandfathering and regulatory jurisdiction are 

resolved. The details of this separate class will be further worked out during 

discussions with the Multi-Stakeholder Discussion Group. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. However, EPA believes that injection for the

primary purpose of long-term storage is sufficiently different from Class II ER operations and

warrants tailored requirements. For example, the volume of CO2 anticipated to be injected in Class

VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will also be

different, with Class VI injection operations involving large volumes of CO2 and likely having

higher pressures within their storage formations than Class II ER projects. 

EPA believes that there are significant differences between how projects are operated, as well as the

risks posed by these different injection activities. The new tailored approach of the GS rule was

designed to address the general risks deep injection may pose to USDWs and was tailored

specifically to address the risks posed by long-term storage of CO2 (i.e., very large volumes, very

long time-periods, and reservoir pressure conditions).

EPA believes that many Class I, Class II, and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule allows the construction of these

wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the

Director that the wells were engineered and constructed to meet the requirements at §146.86(a) and

ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24569

Comment: Rule Provisions: 73 FR 43502 

EPA Rule Issue: 2. Injection of CO2 for the purposes of enhanced oil and gas 

recovery (EOR/EGR), as long as any production is occurring, will continue to be 

permitted under the Class II program. EPA seeks comment on the merits of this 

approach since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted. EPA Notice 43502. 

Anadarko Petroleum Corporation (APC) Response: While it was apparent in the 
preamble that the EPA intended to allow EOR operations to continue under current 

Class II regulations, the rules left some ambiguity to that distinction. In 

order to operate a successful recovery project it is imperative that the oil and 

gas regulators continue to govern EOR operations. APC offers language in our 

comments that would make this more explicit. 

APC strongly supports the proposed approach and the absence of an economic test 

for oil and gas reservoir "depletion." Recognizing though that EPA may face 

pressure to change its approach, APC offers language in our comments on the 

proposed rule for EPA’s consideration for differentiating between wells for 

EOR/EGR and sequestration. 

Additionally, APC, along with the Multi-Stakeholder Discussion Group, supports 

the creation of a subclass under Class II (e.g "Class IIB") for storage 

operations in hydrocarbon formations. See proposed section 146.25. By utilizing 

this approach operators avoid the potential complexity of switching agencies in 

the middle of a project (this is especially important given the sometimes 

conflicting jurisdiction shown between various regulating agencies within a 

state). Also, this allows for the different risk-profile of sequestration in an 

oil and gas reservoir to be taken into account and a different set of regulating 

requirements to be utilized. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. However, EPA believes that injection for the

primary purpose of long-term storage is sufficiently different from Class II ER operations and

warrants tailored requirements. For example, the volume of CO2 anticipated to be injected in Class

VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will also be

different, with Class VI injection operations involving large volumes of CO2 and likely having

higher pressures within their storage formations than Class II ER projects. 

EPA believes that there are significant differences between how projects are operated, as well as the

risks posed by these different injection activities. The new tailored approach of the GS rule was

designed to address the general risks deep injection may pose to USDWs and was tailored

specifically to address the risks posed by long-term storage of CO2 (i.e., very large volumes, very

long time-periods, and reservoir pressure conditions).

EPA believes that many Class I, Class II, and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule allows the construction of these

wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the

Director that the wells were engineered and constructed to meet the requirements at §146.86(a) and

ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA 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 longterm 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.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24624

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: Rule Provision: 144.3 

Anadarko Petroleum Corporation (APC) Comments: ENHANCED OIL RECOVERY (EOR) OR 

ENHANCED GAS RECOVERY (EGR) MEANS ANY ACTIVITY THAT USES FLUIDS, GASES

OR OTHER 

MEANS TO IMPROVE OR INCREASE EXTRACTION OF HYDROCARBONS. 

Rationale: The definition of EOR is necessary to support further comments and 

discussion below. 

Response: EPA includes the following definition of Enhanced Oil or Gas Recovery in the preamble

to the rule: typically, the process of injecting a fluid (e.g., water, brine, or CO2) into an oil or gas

bearing formation to recover residual oil or natural gas. The injected fluid thins (decreases the

viscosity) and/or displaces small amounts of extractable oil and gas, which is then available for

recovery. This is also known as secondary or tertiary recovery.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24625

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 4400

2.4.4.3 Allowing injection above or between USDWs (seeking comment) 

Comment: Rule Provision: 144.6 and 146.5 

Anadarko Petroleum Corporation (APC) Comments: (b) Class II. Wells which inject 

fluids:.... 

(4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC

SEQUESTRATION IS 

OCCURRING DURING OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR

NATURAL GAS 

PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE THAN INSIGNIFICANT

FUTURE 

PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION

AND (II) 

OPERATING PRESSURES ARE NO HIGHER THAN REASONABLY NECESSARY TO

PRODUCE SUCH 

VOLUMES OR RATES; AND 

(5) FOR GEOLOGIC SEQUESTRATION IN SUBSURFACE GEOLOGIC FORMATIONS IN

WHICH 

EXTRACTION OF HYDROCARBONS HAS OCCURRED, IS OCCURRING OR IS

REASONABLY EXPECTED 

TO OCCUR AND WHERE THE CRITERIA OF PARAGRAPH (B)(4) ARE NOT MET. 
(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon 

dioxide STREAMS. beneath the lowermost formation containing a USDW WELLS 

WHERE GEOLOGIC SEQUESTRATION OF CO2 STREAMS OCCURS DURING OR IN

CONNECTION WITH 

EOR OR EGR ARE REGULATED UNDER CLASS II. 

Rationale: The changes to (b) and (f) are to recognize that EOR can have storage 

component, which is consistent with EPA’s intent as expressed in the preamble 

and API’s October 27th meeting with EPA. It is widely recognized that CO2 based 

EOR can provide a significant early opportunity for carbon storage. As EPA 

correctly recognizes, CO2 EOR operations can have a significant storage 

component through capillary trapping or other mechanisms. 

Additionally, there should not be a blanket prohibition concerning injection 

above USDW’s or at specific depths. This is especially true given the 

possibility of changes in the definition of a USDW to include formations greater 

than 10,000 parts per million Total Dissolved Solids. This requirement is not 

necessary for the protection of USDWs and would remove a vast number of viable 

formations from consideration. Industry has shown that it can operate CO2 

injection wells in an EOR context without endangering USDWs that are located 

below the injection zone. An excellent example is the Salt Creek EOR project in 

Wyoming, which has a USDW below the injection zone. Moreover, under the proposed 

rule, there are other measures that would provide real assurance of formation 

integrity and require operators to demonstrate that their project will not 

endanger USDWs, making the lowermost USDW restriction unnecessary. 

Response: EPA did not make the suggested edits. EPA believes that the nature and risks of CO2

injection for the primary purpose of long-term storage pose different risks than injection for the

primary purpose of ER, and has developed new Class VI regulations to address these unique risks.

For example, the volume of CO2 anticipated to be injected for long-term storage is significantly

greater than for ER. Reservoir pressure conditions will also be different, with Class VI injection

operations involving large volumes of CO2 and likely having higher pressures within their storage

formations than Class II ER projects. EPA also recognizes that a by-product of ER activities is that a

certain percentage of the CO2 is trapped in the receiving formation.

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.

Regarding injection into basalts, coal seams, and salt domes, EPA clarifies that the GS rule does not

preclude injection of CO2 into any non-USDW formation types. The purpose of the GS rule is to

ensure protection of USDWs from endangerment, and the rule requires that owners or operators

demonstrate that wells are sited in suitable systems with geologic formations to receive and confine

injected CO2, as required at §146.83 of the GS rule. The Class VI siting, well construction and
operation, monitoring and testing, and post-injection site care and site closure requirements are

designed to ensure that injected CO2 remains within the target formation. If an owner or operator

can demonstrate to the Director's satisfaction that GS in coal seams, basalts, salt domes, or shales

can be accomplished in a manner that protects USDWs and meets all of the requirements of the GS

rule, the project may be permitted as a Class VI well.

EPA acknowledges that there may be unknown risks associated with GS, particularly regarding GS

into formations such as coal seams, basalts, and salt domes, which have been the subject of limited

experimental projects in the past. EPA anticipates that in the short-term, GS into these types of

formations will continue to be experimental (i.e., to test GS technologies and collect data), and will

likely be permitted as Class V experimental technology wells subject to UIC Program Guidance #83.

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs. The final GS rule at §146.95 establishes a

process by which owners or operators can seek a waiver of the Class VI injection depth

requirements. The waiver approach requires the submission of extensive, site-specific information

(in conjunction with the permit application submittal) to demonstrate that injection of CO2 into a

formation that is above or between USDWs can be done in a manner that is protective of USDWs.

The requirements are designed to ensure the owner or operator, the Director, and the Regional

Administrator consider, on a site-specific basis, the implications, benefits, and challenges associated

with GS and ensuring water availability and USDW protection.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24628

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 4324

2.4.4.1.2 Comments opposed to requiring injection below the lowermost USDW 

Comment: Rule Provision: 144.80 

Anadarko Petroleum Corporation (APC) Comments: (b) Class II. Wells which inject 

fluids:........(2) for enhanced recovery of oil or natural gas; (3) FOR EOR OR 

EGR, AND WHERE GEOLOGIC SEQUESTRATION OF A CARBON DIOXIDE STREAM IS

OCCURRING 

DURING OR IN CONNECTION WITH EOR OR EGR OPERATIONS OR ACTIVITIES; and (4)

For 

storage of hydrocarbons.... 

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon 

dioxide STREAMS. WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2 STREAMS

OCCURS DURING 

OR IN CONNECTION WITH EOR OR EGR ARE REGULATED UNDER CLASS II. 

Rationale: See 144.6 

Rule Provision: 146.5 
Anadarko Petroleum Corporation (APC) Comments: b) Class II. Wells which inject 

fluids:..... (4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC 

SEQUESTRATION IS OCCURRING DURING OR IN CONNECTION WITH ENHANCED

RECOVERY OF OIL 

OR NATURAL GAS PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE

THAN 

INSIGNIFICANT FUTURE PRODUCTION VOLUMES OR RATES AS A RESULT OF

CARBON DIOXIDE 

INJECTION AND (II) OPERATING PRESSURES ARE NO HIGHER THAN REASONABLY

NECESSARY 

TO PRODUCE SUCH VOLUMES OR RATES; AND 

(5) FOR GEOLOGIC SEQUESTRATION IN SUBSURFACE GEOLOGIC FORMATIONS IN

WHICH 

EXTRACTION OF HYDROCARBONS HAS OCCURRED, IS OCCURRING OR IS

REASONABLY EXPECTED 

TO OCCUR AND WHERE THE CRITERIA OF PARAGRAPH (B)(4) ARE NOT MET. 

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon 

dioxide STREAMS. Beneath the lowermost formation containing an underground 

source of drinking water (USDW). WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2 

STREAMS OCCURS DURING OR IN CONNECTION WITH EOR OR EGR ARE REGULATED

UNDER CLASS 

II. 

Rationale: See 144.6 

Response: As described above in the response to comment 24625 regarding the suggested edit at

144.6, EPA did not make the suggested change. The Agency disagrees that wells injecting CO2 for

the primary purpose of long-term storage should be regulated under Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

As described above, the final GS rule at §146.95 establishes a process by which owners or operators

can seek a waiver of the Class VI injection depth requirements for injection into non-USDW

formations above and/or between USDWs. 

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24629

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.23(a) 

Anadarko Petroleum Corporation (APC) Comments: (3) WHEN, ON AN ANNUAL BASIS, THE 

FIELD-WIDE AVERAGE CO2 INJECTION TO WITHDRAWAL RATIO IS GREATER THAN

5.0 IN AN 
INJECTION ZONE AND THE AVERAGE RESERVOIR PRESSURE IN THE INJECTION ZONE

BECOMES 

GREATER THAN (A) THE AVERAGE ORIGINAL RESERVOIR PRESSURE IN THE

INJECTION ZONE 

AT THE TIME OF DISCOVERY OF THE RESERVOIR, OR (B) THE AVERAGE DESIGN

OPERATING 

PRESSURE DURING CO2 EOR OR EGR, WHICHEVER IS GREATER, THE DIRECTOR MAY

REQUIRE 

THE OPERATOR OF A CO2 EOR OR EGR PROJECT PERMITTED UNDER CLASS II TO

PROVIDE 

ADDITIONAL INFORMATION AND DATA TO THE DIRECTOR EXPLAINING THE

NECESSITY TO 

INCREASE OR MAINTAIN SUCH PRESSURE. 

IF THE DIRECTOR DETERMINES, BASED ON SITE-SPECIFIC CHARACTERISTICS THAT

THE 

INFORMATION PROVIDED FAILS TO SUPPORT THE NEED TO INCREASE OR MAINTAIN

THE 

AVERAGE RESERVOIR PRESSURE IN THE INJECTION ZONE ABOVE THE AVERAGE

ORIGINAL 

RESERVOIR PRESSURE, OR THE AVERAGE DESIGN OPERATING PRESSURE DURING

CO2 EOR OR 

EGR, THE DIRECTOR MAY REQUIRE THE OPERATOR TO: 

(I) REDUCE OR MAINTAIN THE CO2 EOR OR EGR PROJECT’S FIELD-WIDE AVERAGE

INJECTION 

TO WITHDRAWAL RATIO TO A VALUE SUCH THAT THE AVERAGE RESERVOIR

PRESSURE OR 

AVERAGE DESIGN OPERATING PRESSURE DURING CO2 EOR OR EGR WITHIN THE

INJECTION 

ZONE ESSENTIALLY REMAINS CONSTANT; OR 

(II) APPLY TO RECLASSIFY THE CO2 EOR OR EGR INJECTION WELLS AND INJECTION

ZONE 

COVERED UNDER THE CLASS II PERMIT AS A GEOLOGIC SEQUESTRATION PROJECT

REGULATED 

UNDER THE APPLICABLE WELL CLASS. 

IF THE OPERATOR FAILS TO COMPLY WITH ANY OF THE ABOVE REQUIREMENTS,

THE DIRECTOR 

MAY REVOKE OR MODIFY THE APPLICABLE CLASS II INJECTION PERMIT. 

Rationale: A carbon dioxide stream or carbon dioxide may be injected into a 

reservoir for EOR or EGR. When CO2 comes in contact with oil it dissolves into 

the oil, the oil swells, becomes less viscous and the surface tension between 

the oil and the formation is reduced to such a point that the oil becomes 

mobile. The injection of CO2 also raises the pressure in the formation to a 

desired or designed operating pressure. If achievable, the desired operating 

pressure will be above the miscibility pressure of the oil and CO2. Achieving 

sustained pressures at or above the miscibility pressure will generally allow 
the most efficient and effective recovery of the residual oil remaining in the 

formation. Miscibility pressures are dependent on the oil properties, carbon 

dioxide stream properties and the reservoir temperature. Thus, miscibility 

pressure may be less than the average original discovery pressure of the 

reservoir, or may be equal to or greater than the average original discovery 

pressure of the reservoir. The properties of some oils (generally heavier 

crudes) are such that the miscibility pressure of the oil and CO2 is far in 

excess of the average original discovery pressure of the reservoir and can even 

be greater than the fracture pressure of the reservoir and/or the confining 

zone. 

Once the reservoir pressure reaches the designed or desired average reservoir 

pressure for the CO2 EOR project, the injections of CO2 (or CO2 and water in 

water alternating gas CO2 EOR projects) are managed such that the volumes of CO2 

(or CO2 and water) being injected into the reservoir are generally equal to, or 

slightly greater than, the volumes of fluids being withdrawn from the reservoir 

such that the average designed or desired operating reservoir pressure remains 

relatively constant. The desired or designed operating reservoir pressure may be 

altered from time to time, but the process of raising the average reservoir 

pressure, and then holding the average reservoir pressure relatively constant, 

is the same. 

Therefore, except during periods of reservoir re-pressurization (i.e. the 

beginning of a CO2 EOR project, or for a period of time when the designed or 

desired average reservoir operating pressure is being raised), the ratio of the 

injected volumes (CO2 + water) to the withdrawal volumes (CO2, oil, associated 

natural gas and water) will most likely be less than 1.5. All volumes should be 

determined at average reservoir conditions, or, at a minimum, at the same 

conditions (i.e. same average pressures and temperatures). 

In contrast, a GS project whether occurring after a CO2 EOR project or as a 

standalone GS project is a project in which the primary, but not necessarily 

only, purpose is to inject and store a CO2 stream. Therefore, the ratio of 

injected volumes (CO2) to the withdrawal volumes (CO2 + other formation fluids) 

should be greatly in excess of 1.5 and more than likely an order of magnitude 

greater. 

In order to allow for reasonable fluctuations and variations within CO2-EOR 

projects an injection-withdrawal ratio of 5.0 (3 to 4 times multiple of typical 

injection-withdrawal ratios) is recommended to distinguish between CO2- EOR and 

Geologic Storage projects. The injection-withdrawal ratio should be measured 

over the applicable reporting period required under the applicable permit and 

will be evaluated on a field-wide basis compared to a well-by-well basis (which 

will allow for phased development). 

Response: As described above in the response to comment 24625 regarding the suggested edit at

144.6, EPA did not make the suggested change. The Agency disagrees that wells injecting CO2 for

the primary purpose of long-term storage should be regulated under Class II requirements because

Class II requirements do not address the unique risks posed by GS to ensure protection of USDWs

from endangerment. 
Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24630

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: Rule Provision: 146.25 GEOLOGIC SEQUESTRATION IN OIL OR GAS

RESERVOIRS WITHOUT 

ENHANCED RECOVERY OF OIL OR NATURAL GAS 

Anadarko Petroleum Corporation (APC) Comments: WELLS USED FOR GEOLOGIC 

SEQUESTRATION AND MEETING THE CLASSIFICATION CRITERIA OF SECTION

146.5(B)(5) 

SHALL BE SUBJECT TO THE FOLLOWING REQUIREMENTS: 

(A) EXISTING WELLS THAT MEET OR EXCEED THE CONSTRUCTION REQUIREMENTS

OF § 146.22 

SHALL BE SUBJECT TO PART 146, SUBPART H EXCEPT SECTIONS 146.86 AND 146.87. 

(B) NEW WELLS MUST MET THE CONSTRUCTION REQUIREMENTS OF SECTION 146.22

AND ARE 

SUBJECT TO PART 146, SUBPART H EXCEPT SECTIONS 146.86 AND 146.87 

Rationale: Details of what would be required of "Class IIB" wells are to be 

worked out during future discussions of the Multi-Stakeholder Discussion Group 

(MSDG). However, APC offers this language which is consistent with changes APC 

had suggested before discussions with the MSDG began (see Section 146.81(c)). 

Response: As described above in the response to comment 24625 regarding the suggested edit at

144.6, EPA did not make the suggested change. The Agency disagrees that wells injecting CO2 for

the primary purpose of long-term storage should be regulated under Class II requirements because

Class II requirements do not address the unique risks posed by GS while ensuring protection of

USDWs from endangerment.

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24631

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.81(b) 

Anadarko Petroleum Corporation (APC) Comments: (b) This subpart applies to wells 

used to inject carbon dioxide EXCLUSIVELY for the purpose of geologic 
sequestration, i.e., the long-term containment of a gaseous, liquid or 

supercritical carbon dioxide stream in subsurface geologic formations. IT IS 

RECOGNIZED THAT SOME ACTIVITIES CONDUCTED UNDER CLASS II, INCLUDING CO2

BASED 

EOR OR EGR MAY SEQUESTER A PORTION OF THE CARBON DIOXIDE STREAM USED

FOR EOR OR 

EGR. THIS SUBPART DOES NOT APPLY TO INJECTION OF A CARBON DIOXIDE STREAM

FOR 

PURPOSES OF EOR OR EGR EVEN THOUGH GEOLOGIC SEQUESTRATION OF CARBON

DIOXIDE MAY 

OCCUR DURING OR IN CONNECTION WITH EOR OR EGR OPERATIONS AND/OR

ACTIVITIES. 

Rationale: See 144.6 

Deleted "gaseous, liquid or supercritical" because it was added to the 

definition of CO2 stream. 

Response: As described above in the response to comment 24625 regarding the suggested edit at

144.6, EPA did not make the suggested change. The Agency disagrees that wells injecting CO2 for

the primary purpose of long-term storage should be regulated under Class II requirements because

Class II requirements do not address the unique risks posed by GS while ensuring protection of

USDWs from endangerment.

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24632

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.81(c) 

Anadarko Petroleum Corporation (APC) Comments: (c) ) This subpart applies to 

owners and operators of permit or rule-authorized Class I industrial, Class 

II, or Class V experimental carbon dioxide injection projects who seek to 

apply for a Class VI geologic sequestration permit for their well or wells. If 

the Director determines that USDWs will not be endangered, such wells are 

exempt, at the Director’s discretion, from the casing and cementing requirements 

at §§ 146.86(b) and 146.87(a)(1) through (3). 

Rationale: The reference to Class II wells in section 146.81(c) is no longer 

needed due to addition of 146.25. 

However, if EPA were not to adopt section 146.25, APC would suggest the 

following revisions: 

(c) This subpart applies to owners and operators of permit or rule-authorized 
Class I industrial, Class II WHO HAVE CEASED AND WILL NO LONGER CONTINUE EOR OR

EGR OPERATIONS OR ACTIVITIES, or Class V experimental carbon dioxide injection 

projects who seek to apply for a Class VI geologic sequestration permit for 

their well or wells. If the Director determines that USDWs will not be 

endangered, such wells are exempt, at the Director’s discretion, from the 

casing and cementing requirements at §§ 146.86(b) and 146.87(a)(1) through 

(3). CLASS VI REQUIREMENTS. CLASS II WELLS PERMITTED FOR CO2 INJECTION AND 

THAT HAVE DEMONSTRATED MIT ARE EXEMPT FROM THE REQUIREMENTS AT

§§146.86 AND 

146.87. 

The language allows for the transition of Class II wells to Class VI operations. 

These wells should be allowed to inject CO2 for storage based on their history 

of sound performance under the Class II program as demonstrated by MIT results. 

The language also allows the Director to exercise discretion to exempt other 

Class VI requirements. 

Response: As described above in the response to comment 24625 regarding the suggested edit at

144.6, EPA did not make the suggested change. The Agency disagrees that wells injecting CO2 for

the primary purpose of long-term storage should be regulated under Class II requirements because

Class II requirements do not address the unique risks posed by GS while ensuring protection of

USDWs from endangerment.

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

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 longterm 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.

Commenter Name: Michael Stroben Letter ID: 0209

Commenter Organization: Duke Energy Comment ID: 22685

Other EPA Comment Codes and Descriptions: 2100 1.6 Target Geologic Formations for GS 

Comment: TRANSFERENCE BETWEEN CO2 SEQUESTRATION METHODS 

Duke Energy recognizes that there are differences between Class II and Class VI 

wells. Class II wells are associated with enhanced oil and gas recovery which 

can be an avenue for CO2 sequestration. Aside from deep saline formations, other 

potential sequestration areas include coal seams (Enhanced Coal Bed Methane -- 

ECBM), and shale layers. Since EPA’s proposed rule addresses CO2 volumes in 

millions of tons per year, Duke Energy recommends providing as much flexibility 
as possible when addressing potential CO2 sequestration areas so that the rules 

governing CO2 sequestration are fully transferable should more than one 

sequestration method be selected or should circumstances dictate a change from 

GS to the EOR market or vice versa. Duke Energy believes that allowing 

grandfathering of the proposed provisions to address this type of transfer 

should be allowed except when the Director determines that conversion of a well 

between Class II and Class VI would endanger USDW. 

Response: EPA acknowledges that site-suitability for GS is dependent on a number of factors and

that many formation types may be suitable for GS. The final GS rule does not preclude injection into

any non-USDW formation type, including unmineable coal seams, provided owners or operators can

demonstrate that GS can be performed in a manner that protects USDWs from endangerment. The

Agency anticipates that in the near-term, most GS in unmineable coal seams will continue to be

experimental. Such projects may be permitted as Class V experimental technology wells if they are

of an experimental nature (i.e., to test GS technologies and collect data). EPA will continue to

review data on early GS projects, including those in unmineable coal seams, to determine whether

the appropriate amount and types of information and documentation are required and being

collected. EPA plans, every six years, to collect and review data on GS projects to determine whether

the appropriate amount and types of information and appropriate documentation are being collected,

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

With respect to grandfathering, EPA recognizes that the oil and gas industry has decades of

experience injecting CO2 for ER and that many Class V experimental technology wells are

specifically designed for injection of CO2 and are being constructed to Class I non-hazardous waste

well specifications. In the final rule, at §146.81(c), owners or operators seeking to grandfather

existing Class I, II, or V wells for GS must demonstrate that the grandfathered wells were engineered

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

endangerment in lieu of requirements at §146.86(b) and §146.87(a).

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

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 longterm 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.
EPA agrees that many Class I, Class II, and Class V experimental technology wells are designed and

constructed to withstand exposure to CO2. The final GS rule allows the construction of these wells

to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director

that the wells were engineered and constructed to meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

Commenter Name: Richard Guinn Letter ID: 0210

Commenter Organization: Eastman Chemical Company Comment ID: 22716

Comment: Concern #10: Continuation of Class II for EOR. (Ref: page 43502, Sec. G) 

By proposing different and more restrictive requirements for Class VI wells, EPA 

will create economic or operational barriers that prevent a seamless transition 

from EOR and storage operations to wholly storage operations. EOR can make a 

significant contribution to offset the cost of early CCS demonstration projects. 

For example, EOR can contribute to the investment in pipeline infrastructure 

helping to enable pure CCS operations. Also, CO2 storage operations may continue 

after EOR has ceased, thus reducing the cost of storage, site characterization 

and development. These benefits should be viewed as especially significant in 

light of the difficulties in securing sufficient funds to initially deploy CCS. 

EOR projects could quite feasibly bring CCS deployment forward by many years as 

a considerable quantity of CO2 remains underground during such operations. This 

will reduce the number of target formations where CO2 could be stored. 

Response: EPA believes that injection for the primary purpose of long term storage is sufficiently

different from Class II ER operations and warrants tailored requirements in order to protect USDWs

from endangerment. For example, the volume of CO2 anticipated to be injected in Class VI wells is

significantly greater than for Class II wells. Reservoir pressure conditions will also be different, with

Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II ER projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary

purpose of long term storage obtain a Class VI permit with some special consideration for the fact

that they are transitioning from a well not originally designed to meet Class VI requirements. The

Director has the authority to determine at what point a Class VI permit is required for those projects

that are transitioning from the primary purpose of EOR to long term storage of CO2. The final

regulation provides a set of technical factors for the Director to evaluate in making this

determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs

when there is an increased risk to USDWs as compared to traditional Class II operations while

allowing for site-specific flexibility. 

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 longterm 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.
In response to the comment that establishing a new well class will create economic and operational

barriers, EPA clarifies that the purpose of the GS rule is to ensure protection of USDWs from

endangerment and not to promote or incentivize GS. However, the Agency believes that establishing

a regulatory framework for the future development and deployment of CCS technology can provide

the regulatory and jurisdictional certainty needed to foster development and deployment of CCS

while ensuring USDW protection.

Commenter Name: John King Letter ID: 0211

Commenter Organization: Shell Exploration and Production Company

(SEPCo)

Comment ID:

22758

Comment: B. SEPCo Supports Continued Application of the Class II Regulations to CO2 

Injection in the Enhanced Oil or Gas Recovery Context and the Creation of "Class 

VI" Regulations to Address Other CO2 Injection Wells Used for GS. 

CO2 injection wells are currently permitted as Class II or Class V "experimental 

technology: wells. Under the proposed rule, Class II CO2 injection would remain 

under Class II, and a new classification " Class VI " would be created for GS. 

This approach makes sense. CO2 injection for purposes of enhanced oil or gas 

recovery ("EOR/EGR") has been successfully regulated as Class II injection for 

decades, and there is nothing to justify any disruption of the existing 

regulatory regime for the thousands of injection wells already in use in these 

operations. For other GS injection projects, Class VI regulations would permit a 

more structured basis for regulation than the Class V regulations. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. However, the Agency believes that the nature

and risks of CO2 injection for the primary purpose of long term storage poses different risks than

injection for the primary purpose of EOR, and therefore has developed new Class VI regulations to

address these unique risks. For example, the volume of CO2 anticipated to be injected for long term

storage is significantly greater than for EOR operations. Reservoir pressure conditions will also be

different, with Class VI injection operations involving large volumes of CO2 and likely having

higher pressures within their storage formations than Class II ER projects.

Commenter Name: John King Letter ID: 0211

Commenter Organization: Shell Exploration and Production Company

(SEPCo)

Comment ID:

22775

Other EPA Comment Codes and Descriptions: 4500 2.5 Proposed Mechanical Integrity Testing

(MIT) Requirements (40 CFR 146.89) 

Comment: E. Mechanical Integrity Testing (MIT) Requirements 

The proposed rule suggests, "MIT requirements for GS wells should be tailored to 

address the unique properties of CO2, specifically its buoyancy and potential 

corrosivity." 73 Fed. Reg. at 43513. As previously discussed, however, the 

buoyancy of CO2 is a relatively trivial factor in relation to the cone of 

influence created by injection pressure during injection, a factor that makes 

buoyancy virtually irrelevant as a driving force for upward migration through 

the injection well borehole during the operational life of a GS well. 
Accordingly, there is no basis to suggest that the buoyancy of CO2 is relevant 

to be considered in establishing mechanical integrity testing requirements for 

GS wells. Similarly -- as also previously discussed -- CO2 is not corrosive and 

cannot be expected to cause corrosion problems for the injection well (including 

down-hole cement) unless the CO2 stream itself contains water. Consequently, 

corrosion generally should not be expected to be a problem and concerns related 

to corrosion do not justify any particularly stringent requirements for GS 

wells. Experience with CO2 in the EOR context fully supports these conclusions. 

In fact, the Class II MIT requirements have been sufficient for CO2 injection in 

the EOR/EGR context, and there is no reason why they should not be sufficient in 

the GS context as well. 

Response: EPA disagrees with this comment. EPA has identified buoyancy as one of the unique

characteristics of CO2 that warrants special consideration. The Agency believes that buoyancy of the

injected CO2 coupled with other characteristics of GS operations, including the large injection

volumes and timeframes of storage, present operating circumstances at Class VI wells that are

different from other classes of wells and injectates regulated by the UIC Program. 

Supercritical CO2 has a lower density than the native formation fluids in the target injection

formations typically anticipated for GS. Once injected, the more buoyant CO2 will have a tendency

to migrate upwards. This expected movement is similar to the situation found in some Class I wells

(see Revision to the Federal UIC Requirements for Class I--Municipal Wells in Florida; 65 FR

42234, July 7, 2000). Well monitoring in Florida identified upward fluid movement from some Class

I municipal wells attributed to the lower density of the injection fluid (in this case due to lower TDS)

compared to the native formation fluids. The injection fluids rose to the top of the injection zone

preferentially through fractures. Such migration could occur through conduits in the injection

wellbore as well as in the target formations. In the case of GS, any cracks or fractures in the cement

casing for a GS injection well would also serve as conduits for upward migration of more buoyant

fluids. External MITs, which test for movement along the borehole, are therefore appropriate

requirements for GS wells. 

EPA disagrees that the MIT requirements for Class VI wells are excessive. MITs are a long-standing

and proven method of providing early warning of potential problems in the injection well system

before they lead to leakage and/or endangerment of USDWs. 

EPA also disagrees that corrosivity is not a concern. While some studies of cement performance

have shown encouraging results, other information gathered through research and field data provided

in the rulemaking docket, show evidence of chemical alteration and suggest a potential for

degradation to occur and potentially endanger USDWs. Although laboratory and field studies

suggest that corrosion problems may not be severe, such problems cannot be conclusively ruled out.

Laboratory exploration of cement alteration and degradation is an ongoing research area, and fieldbased 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

MIT requirements at §146.89 are justified.

A comprehensive review of MIT results found that Class I wells injecting corrosive fluids fail MITs

at rates two to three times higher than those that inject non-corrosive fluids (USEPA, 1999). Given

the potential for CO2 to be corrosive (when in the presence of water), there is a potential risk factor
for MIT failure and the tailored MIT requirements are appropriate. 

EPA agrees that Class II well operators have decades of experience injecting CO2. However, EPA

believes that significant operational differences exist between Class II and Class VI wells. For

example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than

for Class II wells. Also, reservoir pressure conditions will be different with ER production

(extraction) serving to reduce reservoir pressure for Class II operations while Class VI injection

operations will have no comparable de-pressuring activities. For these reasons, EPA believes that

injection of CO2 for GS warrants more frequent MITs to provide sufficient early warning of the

potential for MI failures due to the corrosivity of the CO2 or reservoir pressure conditions associated

with CO2 GS. 

Commenter Name: Dennis R. James Letter ID: 0214

Commenter Organization: North American Coal Corporation (NAC) Comment ID: 22959

Comment: The proposed rule states, "the Agency defined five classes of injection wells at 

40 CFR 144.6, based on similarities in the fluids injected, construction, 

injection depth, design, and operating techniques". However, the Agency is 

proposing a new class of well based more so on use than the afore stated 

criteria. A Class II well injecting CO2 into a deep oil reservoir may have the 

same physical requirements as a proposed Class VI well injecting CO2 into a 

similar stratum. 

EPA is making the assumption that all Class II wells (EOR) will inject CO2 at 

relatively low pressure and all Class VI wells (GS) will inject CO2 at very high 

pressure; therefore, the use determines the operating condition and requires the 

separate well classification. EOR is far from being a mature and widely 

deployed technology. GS is still very experimental with very limited testing at 

scale. Therefore, it is possible and probably likely that as EOR and GS 

technologies develop, the range of operating techniques and depths will have 

significant overlaps. 

As such, it would be more appropriate to distinguish CO2 injection wells based 

on the planned operating techniques and conditions than on ultimate use. This 

would improve the protection provided by the intent of the rule. 

Wells permitted for EOR and EGR injection of CO2 do sequester CO2. If these 

wells were permitted for a given range of operating conditions and parameters, 

then there would be no question about a well being used for GS. 

Furthermore, classifying wells as EOR/EGR or GS is problematic. EOR/AGR 

activities do sequester CO2 while they recover oil and gas. If use is the 

classification criteria, at what point would a Class II EOR/EGR well need to be 

reclassified as a Class VI GS well? The recovery of hydrocarbons from an 

EOR/EGR project will diminish as the reserve is depleted. This means that the 

volume of CO2 injected will result in less oil and gas production: Leading to 

the question of when does a Class II well need to be reclassified as a Class VI? 

If the requirement is only that some amount of hydrocarbon be produced, then 

many GS projects could opt for Class II permits. 
If the intent of the rule is to protect USDWs from the effects of CO2, then any 

well injecting CO2 should be subject to the same permitting requirements for the 

given operating environment. To do otherwise for the sake of bureaucratic 

simplicity merely increases the regulatory burden on operators without adding 

meaningful protection of the environment. 

Response: EPA disagrees that the risks posed by long term storage of CO2 for GS can be addressed

under existing UIC requirements, such as those for Class II wells. EPA believes that there are

significant differences between how EOR and GS projects are operated, as well as different risks

posed by these different injection activities. The new tailored approach of the GS rule was designed

to address the general risks deep injection may pose to USDWs and was tailored specifically to

address the risks posed by long term storage of CO2 (i.e., very large volumes, very long timeperiods, and reservoir pressure conditions). EPA acknowledges that some CO2 is sequestered during

EOR operations; however, the pressure increases associated with injecting high volumes of CO2

changes the risk profiles for these wells increases when transitioning from Class II to Class VI.

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 longterm 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.

Commenter Name: Ronald Evans Letter ID: 0215

Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24272

Other EPA Comment Codes and Descriptions: 1210 1.1.1 Comments about the proposed rule 

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. 

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 longterm 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 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.

Commenter Name: Ronald Evans Letter ID: 0215

Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24276

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 

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 

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. 

[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). 
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 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 longterm 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.

Commenter Name: Ronald Evans Letter ID: 0215

Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24277

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 

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. 

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 longterm 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.
Commenter Name: Tom Ward Letter ID: 0219

Commenter Organization: Sandridge Energy Corporation Comment ID: 21568

Comment: 1. EPA UIC Regulations Must Recognize That EOR Using CO2 Increases Domestic 

Energy Supplies And Utilizes And Simultaneously Sequesters CO2 That Would 

Otherwise Be Vented Into The Atmosphere 

As explained below, Sandridge believes that the EPA must issue regulations under 

the UIC in a manner that enables new and existing owners and operators of Class 

II wells to use those wells to inject CO2 for EOR without additional and undue 

risks and costs. This process has and will significantly increase domestic 

sources of energy, while utilizing and simultaneously sequestering CO2 that 

would otherwise be vented into the atmosphere. 

Response: The Agency believes that the nature and risks of CO2 injection for the primary purpose

of long term storage pose different risks than injection for the primary purpose of ER, and therefore

has developed new Class VI regulations to address these unique risks. EPA clarifies that the rule

does not create any additional requirements for Class II EOR wells that inject CO2 for enhanced

recovery of oil or gas.

In response to the comment about domestic energy production, EPA clarifies that the purpose of the

GS rule is to ensure protection of USDWs from endangerment and not to promote or incentivize GS.

However, the Agency believes that establishing a regulatory framework for the future development

and deployment of CCS technology may provide the regulatory and jurisdictional certainty needed to

foster development and deployment of CCS while ensuring USDW protection.

Commenter Name: Tom Ward Letter ID: 0219

Commenter Organization: Sandridge Energy Corporation Comment ID: 21569

Comment: A. EOR Using CO2 Has Significant Economic And Environmental Benefits 

EOR using CO2 has and will substantially increase the U.S. domestic energy 

supply, which places the country in a more favorable economic and national 

security position. After the primary and secondary phases of oil recovery are 

complete, CO2 may be injected into oil and gas fields and reservoirs during a 

tertiary recovery phase known as EOR to recover between 10 and 50 percent of the 

oil originally contained in the reservoir. According to the Department of Energy 

(DOE), approximately 1,673 fields/reservoirs, which account for 146 billion 

barrels of original oil in place and 65 billion barrels of remaining immobile 

oil, are candidates for CO2-miscible flooding in the U.S. The latest report on 

"Storing CO2 with Enhanced Oil Recovery" published by the DOE's National Energy 

Technology Laboratory (the "DOE-NETL Report") explains that "the 39 to 48 

billion barrels of economically recoverable domestic oil[,] economically 

recoverable from storing CO2 with EOR[,] would help displace imports, [create] a 

path toward energy independence...[and] help build pipeline infrastructure 

subsequently usable for storing CO2 in saline formations." 

EOR using CO2 contributes to the U.S. domestic energy supply in an 

environmentally responsible way that traps CO2 that would otherwise be vented 

into the atmosphere. CO2 is not simply injected into a formation when it is used 

for EOR; CO2 is also sequestered simultaneously during and after oil and gas 
production resulting from EOR with CO2. When CO2 is injected for EOR, 

approximately one-third to one-half of it becomes trapped and stored in the 

field or reservoir in perpetuity and the remainder of the CO2 is produced with 

the oil and then separated and reinjected to further enhance production. Each 

subsequent injection traps even more of the original CO2, and ultimately nearly 

all of the CO2 is sequestered in the field or reservoir. Because of this 

sequestration, oil and gas producers must continually obtain additional amounts 

of the greenhouse gas, which is then ultimately sequestered-instead of ventedinto the atmosphere. The DOE-NETL Report estimates that "significant volumes of 

CO2 (ranging from 10 to 13 billion metric tons depending on oil price) can be 

stored with enhanced oil recovery." 

In fact, EOR is the only commercially available near-term way to sequester CO2. 

In his recent testimony during the U.S. House Energy and Commerce Subcommittee 

on Environment and Hazardous Materials hearing on "Carbon Sequestration: Risks, 

Opportunities and Protection of Drinking Water," Dr. Ian Duncan from the Bureau 

of Economic Geology at the University of Texas at Austin stated that " [i]n the 

near term, CO2-enhanced oil recovery, combined with appropriate monitoring, 

mitigation and verification, can make a significant contribution to putting manmade CO2 into permanent storage in depleted oil reservoirs, and it may have been 

a little confusing in some of the previous testimony where it was perhaps 

suggested that CO2 involved in enhanced oil recovery is just there to recover 

the oil." 

The time-tested and successful regulation of CO2 sequestration in connection 

with EOR under Class II requirements (as opposed to the ongoing developing tests 

and regulation of CO2 sequestration from large-scale GS projects) is the reason 

that experts point to EOR using CO2 as the only near-term commercially available 

way to reduce greenhouse gas emissions through carbon sequestration. Injecting 

relatively small amounts of CO2 at relatively light pressures for EOR purposes 

has been tested and regulated since the early 1970s under Class II requirements. 

These requirements include rules to ensure proper monitoring, mitigation and 

verification and have resulted in the successful regulation of CO2 used for EOR. 

Testament to this successful regulation is the fact that the EPA has 

acknowledged that there has been no known impact-positive or negative-of CO2 

used for EOR on underground sources of drinking water.[1] 

Since EOR using CO2 has been successfully regulated under the Class II program 

for over three decades, Sandridge believes that the EPA should continue to 

monitor EOR using CO2 under that program. Accordingly, there must be a 

recognized line between GS that occurs in conjunction with business-as-usua1 

EOR where CO2 is injected at relatively low volumes and at relatively low 

pressures, and GS during which CO2 is injected at high volumes at high 

pressures for the primary purpose of permanent sequestration. Developing such a 

line will not only benefit regulators by clarifying the boundaries between the 

two types of activities, but also companies engaging in EOR using CO2 that have 

already factored the Class II requirements into their costs and risk 

assessments. If there is doubt that business-as-usua1 EOR using CO2 may be 

subject to new regulations, companies may decide that taking steps necessary to 

qualify such projects for carbon credits are no longer worth it, thereby 
potentially depriving the U.S. of important verifiable carbon sequestration 

alternatives. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. The Agency believes that the nature and risks of

CO2 injection for the primary purpose of long term storage pose different risks than injection for the

primary purpose of EOR, and therefore has developed new Class VI regulations to address these

unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is

significantly greater than for ER operations. Reservoir pressure conditions will also be different, with

Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II ER projects. 

As described above, EPA clarifies that the purpose of the GS rule is to ensure protection of USDWs

from endangerment and not to address domestic energy production. The Agency believes that

establishing a regulatory framework for the future development and deployment of CCS technology

may provide the regulatory and jurisdictional certainty needed to foster development and deployment

of CCS while ensuring USDW protection. 

Furthermore, EPA clarifies that the Agency is using an adaptive approach to regulate GS injection.

The Agency plans, every six years, to collect and review data on GS projects, including monitoring

EOR projects using CO2, to determine whether the appropriate amount and types of information and

appropriate documentation are being collected, and to determine if modifications to the requirements

are appropriate or necessary.

Commenter Name: Tom Ward Letter ID: 0219

Commenter Organization: Sandridge Energy Corporation Comment ID: 21570

Comment: B. Benefits From EOR With CO2 Can Only Be Realized If Costs Are Contained 

As suggested above, Sandridge believes that the economic and environmental 

benefits from EOR using CO2 will only continue and grow if costs and risks are 

contained. As it is, under the current business and regulatory environments, 

cost is a major barrier to EOR with CO2, Occidental Petroleum Vice President of 

Worldwide Engineering and Technical Services William Roby illustrated the 

enormous costs associated with EOR using CO2 in recent testimony when he 

described that "[Occidental] estimate[s] that using CO2 enhanced recovery at 

[its] Permian Basin operations increases the cost of recovering a barrel of oil 

by more than 50 percent over typical primary and secondary recovery operations." 

First, a business must spend significant capital to build the pipeline 

infrastructure necessary to carry the CO2 from its source to the targeted fields 

and reservoirs. In order to make the necessary investments in EOR with CO2, a 

business must be able to figure that it will recover the capital costs from the 

long-term oil production potential of the target formation and the expectations 

of future oil prices. Oil price volatility is "a significant deterrent to CO2 

pipeline and project investment by industry, particularly for smaller 

independent producers." EOR with CO2 becomes more attractive from a business 

cost perspective as oil prices go up. 

Given recent and future oil price volatility and the enormous costs associated 
with EOR using CO2, it is crucial for businesses engaging in that activity to 

keep costs as stable and predictable as possible. Since these businesses have 

been operating under Class II regulations, they are able to predict those 

regulatory costs with some precision. This prediction has encouraged businesses 

to invest in CO2 since they do not have to factor much regulatory volatility 

into their business plans for conducting EOR with CO2. 

II. EPA Regulations Must Reflect A Bright Line Between CO2 Sequestered In 

Conjunction With Business-As-Usual EOR Regulated Under Current Class II 

Regulations And CO2 Sequestered For The Purpose Of Permanent GS Regulated Under 

A New Regime 

Sandridge is concerned that the Proposed Rule does not adequately recognize that 

industry may only be expected to continue investing in EOR projects using CO2 as 

long as industry may rely on the activity's regulation under tested and 

predictable Class II requirements for injection wells. In its current form, the 

Proposed Rule indicates that "[i]njection of CO2 for the purposes of enhanced 

oil and gas recovery.. .,as long as any production is occurring, will continue 

to be permitted under the Class II program" (emphasis added). However, the 

Proposed Rule does not set a minimum level at which production must be occurring 

to appropriately distinguish injection of CO2 for businessas-usual EOR that 

will be regulated under Class II regulations, from injection of CO2 for GS that 

will be regulated under a new class. [2] 

This omission increases the potential risks and costs to industry and could lead 

to a chilling effect on industry efforts to seek carbon credits. As such, it is 

important to make clear that CO2 sequestration can occur in conjunction with 

business-as-usual EOR with the proper level of regulatory scrutiny under Class 

II regulations, and it can also take place in conjunction with activities 

specifically designed to sequester large amounts of CO2 that will be regulated 

under a new regime. Sandridge believes that it is crucial that EPA’s final rule 

makes this clarification to help ensure that industry continues its EOR 

activities and taking steps necessary to earn carbon credits, especially at this 

time when the U.S. is searching for ways to increase the domestic supply of 

energy in ways that reduce greenhouse gas emissions. Accordingly, as a member of 

an industry actively involved in EOR using CO2, Sandridge believes that EPA 

should ensure that the final rule contains a bright line, minimum level at which 

production must be occurring to appropriately distinguish injection of CO2 for 

business-as-usual EOR that will be regulated under Class II regulations from 

injection of CO2 for permanent GS that will be regulated under a new class. 

Response: In response to the comment that establishing a new well class will create economic and

operational barriers, EPA clarifies that this comment is outside the scope of the rulemaking. The

purpose of the GS rule is to ensure protection of USDWs from endangerment and not to promote or

incentivize the deployment of GS. However, the Agency believes that establishing a regulatory

framework for the future development and deployment of CCS technology can provide the

regulatory and jurisdictional certainty needed to foster development and deployment of CCS while

ensuring USDW protection. 

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: Tom Ward Letter ID: 0219

Commenter Organization: Sandridge Energy Corporation Comment ID: 21571

Comment: III. Suggested Injection Well Definition To Create Necessary Bright Line Between 

Class II And Class VI CO2 Injection Activities 

Sandridge suggests that EPA continue to regulate under Class II requirements 

injection wells that meet the following definition: 

(1) For enhanced recovery of oil or natural gas where geologic sequestration is 

occurring during or in connection with enhanced recovery of oil or natural gas 

provided (i) there is reasonable expectation of more than insignificant future 

production volumes or rates as a result of carbon dioxide injection and (ii) 

operating pressures are no higher than reasonably necessary to produce such 

volumes or rates. This suggested formula to define injection wells that should 

be regulated under Class II has been reviewed and approved by several interested 

parties, including representatives of environmental organizations, as well as 

industry. Therefore, Sandridge believes that EPA should 1) be satisfied that the 

definition has been well-vetted and enjoys broad support, and 2) adopt the 

formula as the standard that separates CO2 sequestration that occurs in 

conjunction with business-as- usual EOR that will continue to be regulated under 

traditional Class II requirements, from CO2 sequestration that occurs as a 

result of CO2 injection in large quantities for the sole purpose of permanent GS 

that may be regulated under a new class. 

IV. Conclusion 

It is widely accepted that business-as-usual EOR using CO2 has the potential to 

unlock enormous new domestic energy supplies while reducing CO2 through 

simultaneous sequestration. Since this important industry practice has been 

tested and regulated successfully for more than three decades, with no known 

negative impacts to the environment or underground sources of drinking water, 

Sandridge urges the EPA to ensure that industry will continue to invest in EOR 

using CO2 (and thereby simultaneously storing CO2 which would otherwise be 

vented into the atmosphere) by revising the Proposed Rule to define and 

distinguish CO2 sequestration that occurs in conjunction with business-as-usual 

EOR that will continue to be regulated under traditional Class II requirements, 

from CO2 sequestration that occurs as a result of CO2 injection in large 

quantities for the sole purpose of permanent GS that may be regulated under a 

new class. For the reasons explained above, Sandridge suggests the EPA create 
this bright line by classifying injection wells that meet the following formula 

as those that will be regulated under Class II: 

(1) For enhanced recovery of oil or natural gas where geologic sequestration is 

occurring during or in connection with enhanced recovery of oil or natural gas 

provided (i) there is reasonable expectation of more than insignificant future 

production volumes or rates as a result of carbon dioxide injection and (ii) 

operating pressures are no higher than reasonably necessary to produce such 

volumes or rates. 

Sandridge recognizes that EPA is considering new regulations for the injection 

of CO2 at volumes and pressures that go beyond traditional EOR activities for 

which the proposed Class VI requirements may be appropriate. However, in these 

comments, Sandridge only seeks to point out the extraordinarily important 

business, environmental, and regulatory reasons why it believes that the EPA 

must ensure that the final rule properly distinguishes CO2 injected for 

business-asusual EOR from CO2 injected for GS. Thank you for your consideration 

of these comments. 

Response: EPA believes that injection for the primary purpose of long term storage is sufficiently

different from Class II ER operations and warrants tailored requirements in order to protect USDWs

from endangerment. For example, the volume of CO2 anticipated to be injected in Class VI wells is

significantly greater than for Class II wells. Reservoir pressure conditions will also be different, with

Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II EOR projects, which may lead to fluid movement. 

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 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 longterm 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.

Commenter Name: Edward Steadman Letter ID: 0220

Commenter Organization: The Energy and Environmental Research Center at the

University of North Dakota

Comment ID:

21575
Comment: A final comment has to do with any rules or policies that might marginalize EOR 

as a sequestration tool. The PCOR Partnership believes the early-captured CO2 

will be injected in large volumes and stored during existing and new commercial 

(i.e., EOR) operations. The only reference to the use of EOR sites for 

sequestration is contained in proposed rule § 146.83(c) which discusses 

repermitting existing wells as Class VI storage wells. The emission reduction 

potential and sequestration associated with EOR are immense, and revenues from 

the oil produced will offset the cost to the economy and will, ultimately, 

accelerate more widespread deployment of CCS technologies. With the growing 

energy concerns in the United States, the contributions of CO2 EOR in the 

advancement of CCS need to be embraced. This reality needs to be further 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. However, EPA believes that injection for the primary purpose of long term storage is

sufficiently different from Class II ER operations and warrants tailored requirements. For example,

the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class

II wells. Reservoir pressure conditions will also be different, with Class VI injection operations

involving large volumes of CO2 and likely having higher pressures within their storage formations

than Class II ER projects. 

EPA clarifies that the purpose of the GS rule is to ensure protection of USDWs from endangerment

and not to promote or incentivize GS deployment. However, the Agency believes that establishing a

regulatory framework for the future development and deployment of CCS technology can provide

the regulatory and jurisdictional certainty needed to foster development and deployment of CCS

while ensuring USDW protection.

Commenter Name: Edward Steadman Letter ID: 0220

Commenter Organization: The Energy and Environmental Research Center at the

University of North Dakota

Comment ID:

21593

Comment: Page 43502. G. How Would This Proposal Affect Existing Injection Wells under the 

UIC Program? 

The regulatory regime should readily accommodate the adoption of Class II wells 

into any new category. Unfortunately, this entire section gives the impression 

that storage is not occurring during EOR activities, which is not true. EOR 

provides partial storage capability until such time as the recovery of 

hydrocarbons ceases and all production activities are ended. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. Furthermore, EPA recognizes that some CO2 is sequestered when injecting CO2 for purposes

of EOR. However, the Agency believes that the nature and risks of CO2 injection for the primary

purpose of long term storage poses different risks than injection for the primary purpose of EOR,

and therefore has developed new Class VI regulations to address these unique risks. For example, the

volume of CO2 anticipated to be injected for long term storage is significantly greater than for EOR

operations. Reservoir pressure conditions will also be different, with Class VI injection operations

involving large volumes of CO2 and likely having higher pressures within their storage formations

than Class II EOR projects.
Commenter Name: Darrick Eugene Letter ID: 0223

Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23958

Comment: As currently written, EPA creates a separate Class VI category of UIC regulation 

for CO2 storage in their attempt to avoid the Class I waste moniker. Where CO2 

storage sites can meet the qualifications for permitting, the TxCCSA believes 

that geologic storage is substantially similar to EOR/EGR and in those instances 

any regulations for Class VI wells should reflect more closely UIC Class II 

standards instead of the more stringent Class I hazardous waste well standards. 

If the geologic storage site doesn't qualify or if the injectate composition is 

such that it is truly a waste stream, then the well requirements should more 

directly reflect the requirements of Class I UIC standards, as with the proposed 

Class VI well category. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of EOR, and that sites used for ER may be suitable for GS and may be among the first

GS sites. However, the Agency believes that the nature and risks of CO2 injection for the primary

purpose of long term storage poses different risks than injection for the primary purpose of EOR,

and therefore has developed new Class VI regulations to address these unique risks. For example, the

volume of CO2 anticipated to be injected for long term storage is significantly greater than for EOR

operations. Reservoir pressure conditions will also be different, with Class VI injection operations

involving large volumes of CO2 and likely having higher pressures within their storage formations

than Class II EOR projects which may lead to fluid movement that endangers an USDW. 

Therefore, EPA believes that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS.

Commenter Name: Darrick Eugene Letter ID: 0223

Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23962

Comment: Point #5: The lack of considerationfor simultaneous storage 

and hydrocarbon production. Another concern raised by the proposed EPA rule 

involves the lack of consideration for storage of CO2 during oil and gas 

production. At TxCCSA, we strongly believe that the early CO2 captured from 

industry sources will be injected in substantial volumes and stored during 

existing and new EaR operations. If the capturing company receives no value 

("offset") for reducing emissions, the capture project will not proceed. 

The only reference to the use of EOR sites for storage is contained in proposed 

rule § 146.83(c) which discusses how existing wells, particularly Class II wells 

used for EOR, can be carried over or re-permitted as Class VI wells. The EPA 

should give greater emphasis to the commercial significance of CO2-driven EOR 

under the existing Class 11 well permitting framework. Given the 36+ years of 

experience with CO2 floods in the Permian Basin of West Texas, EOR will serve as 

a bridge to full-scale deployment of geologic storage by facilitating 

infrastructure development. Currently, 3500 miles of pipeline infrastructure 
exist to transport CO2,and CO2-driven EOR's demand for more CO2 is poised to 

increase that number. Furthermore, some estimate that over 8 trillion cubic feet 

of C02 has been stored in the Permian Basin alone. These significant volumes 

represent an already mature industry that should be encouraged to expand. 

The EPA should demonstrate a greater recognition of CO2-driven EOR and 

simultaneously protect underground sources of drinking water by restructuring the 

Proposed Rule, reserving the new Class VI for use in permitting wells in certain 

non-hydrocarbon producing target formations and providing a mechanism that 

recognizes owners and operators seeking to engage in hydrocarbon related 

geologic storage under Class II well permits. This mechanism could take the form 

of a Class II subclass that would overlay Class II permit requirements with 

additional area of review, monitoring, reporting, postinjection site care and 

closure requirements. Such a regulatory regime would also recognize the 

differences between non-hydrocarbon related target formations and both depleted 

and producing oil & gas reservoirs. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. Furthermore, EPA recognizes that some CO2 is sequestered when injected for purposes of EOR

However, the Agency believes that the nature and risks of CO2 injection for the primary purpose of

long term storage poses different risks than injection for the primary purpose of ER, and therefore

has developed new Class VI regulations to address these unique risks. For example, the volume of

CO2 anticipated to be injected for long term storage is significantly greater than for ER operations.

Reservoir pressure conditions will also be different, with Class VI injection operations involving

large volumes of CO2 and likely having higher pressures within their storage formations than Class

II ER projects, which may lead to fluid movement that endangers an USDW.

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 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 longterm 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.

EPA clarifies that the GS rule does not require any facilities to sequester CO2; nor does it create an

economic incentive to do so. The purpose of the GS regulation is to ensure that, where deployed, GS
is conducted in a manner that does not endanger USDWs.

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21650

Comment: (A) Importance of EPA’s Recognition That EOR/EGR and 

Storage of CO2 Occur At the Same Time 

HEI commends EPA for its recognition, as stated in the Preamble of the Proposed 

Rule, that oil and gas reservoirs will play a valuable role in the geologic 

storage of CO2. Two of the reasons cited by EPA are: (1) oil and gas reservoirs 

are natural storage containers that have trapped fluid (both liquid and gaseous) 

hydrocarbons for millions of years; and (2) oil and gas exploration and 

production activities have created a wealth of knowledge and geologic data that 

can support the site characterization process for geologic sequestration. (73 

Fed. Reg. at 43502-03.) Indeed, oil and gas reservoirs have proven capable of 

containing water-buoyant fluids for millions of years. These reservoirs are well 

studied and they offer the best opportunity to kick-start large-scale geologic 

sequestration of CO2, building on 100 years of oil and gas field operating 

experience. Consequently, many oil and gas reservoirs are available now to 

serve CCS projects at a commercial scale, and will add insights for subsequent 

application to other formations. 

EPA should provide further discussion and acknowledgement in its Proposed Rule 

that, when CO2 is injected for use in EOR/EGR projects, geologic sequestration 

(or long term storage) of CO2 occurs during EOR/EGR operations and continues 

after EOR/EGR operations cease ("EOR and Storage"). Furthermore, it is critical 

that EPA support and encourage geologic sequestration of CO2 in these wellstudied and proven oil and gas reservoirs by amending certain elements of the 

Proposed Rule to clarify and streamline requirements. EPA’s recognition of EOR 

and Storage will provide a much-needed near-term, economic incentive to CCS 

projects. Incentivizing the use of anthropogenic CO2 for EOR/EGR will provide 

many lasting benefits to the United States, by significantly reducing current 

CO2 emissions and increasing energy security. 

It has become increasingly clear that early EOR and Storage projects will 

significantly advance the deployment of CCS technology and geologic 

sequestration of CO2 for many reasons: 

- Oil and gas formations offer the best characterized sites among potential 

sinks for anthropogenic CO2; 

- Much of the required infrastructure and operational experience is already in 

place; 

- Class II requirements have proven to be an effective regulatory framework in 

protecting USDWs in the context of CO2 EOR operations, evidenced by more than 30 

years of experience in the Permian Basin and more than 25 years of miscible gas 

injection projects on the North Slope of Alaska (where CO2 comprises 25% of the 

miscible gas injected); 
- Demand for large volumes of CO2 for EOR is increasing [FN1]; and 

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

CCS projects. 

EOR and Storage have the added benefit of increasing domestic energy supplies in 

the face of increasing demand. Carbon dioxide injection has proven capable of 

increasing oil or gas recovery in mature fields from 5% to more than 20%. The 

Department of Energy estimates that EOR has the potential to add 40-80 billion 

barrels of oil reserves in the United States, which is 2 to 4 times the current 

United States’s total proven reserve. The Intergovernmental Panel on Climate 

Change ("IPCC") has agreed that EOR technology can provide a significant kickstart on proving geologic sequestration of CO2 on a commercial scale. Indeed, 

the early commercial scale CCS projects will probably employ EOR and Storage as 

their basis of design, which will extensively inform the technical development 

and safe deployment of CCS projects in other types of geologic formations.[FN2] 

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

Currently, EOR/EGR operators purchase CO2 for injection. This can represent a 

significant portion of the cost of an EOR/EGR project. Consequently, CO2 is a 

valuable commodity to EOR/EGR operators and is treated accordingly. Because it 

is a valuable commodity in EOR/EGR operations, CO2 is not emitted or vented to 

the atmosphere during operations or after operations cease. Any injected CO2 

that returns to the surface during production operations is separated from the 

hydrocarbons and re-injected for additional enhanced recovery use. 

Approximately 30% to 50% of the injected CO2 volume typically remains 

permanently stored in the oil or gas reservoir after production operations 

cease. The injected CO2 is monitored in the formation and injection operations 

are designed to minimize CO2 procurement and maximize oil (and recycled CO2) 

production. Despite best efforts to re-use all the CO2, additional trapping of 

CO2 occurs with each subsequent injection cycle, necessitating further purchases 

of CO2. When the EOR operations cease (and the field is blown down to recover 

any CO2 available for use in another operation), wells are closed and the 

remainder of the injected CO2 remains permanently stored underground. However, 

an EOR operator could quite easily, at its option, manage operations to store 

the injected CO2 for the long term (rather than recover it). 

The foregoing demonstrates that, based on decades of experience gained in 

existing EOR/EGR operations utilizing CO2, EPA should acknowledge in the Final 

Rule preamble that injected CO2 can be trapped and stored for long term during 

EOR operations and continues afterwards. Furthermore, existing Class II 

regulations and industry practice employ proven methodologies to conduct these 

operations in a safe manner that is protective of USDWs. 

(2) Requested Amendments to Proposed Rule 

For the reasons stated above, EPA should expand its discussion and acknowledge 
in the Final Rule text and preamble that, when CO2 is injected for use in 

EOR/EGR projects, geologic sequestration (or long term storage) of CO2 occurs 

during EOR/EGR operations and continues after operations cease - thus EOR and 

Storage. HEI supports EPA’s statement that EOR/EGR, as long as any production is 

occurring, will continue to be permitted under the Class II program. 

We also understand that it is EPA’s intent, which we strongly support, that the 

proven Class II program applies to storage of CO2 that is occurring during and 

in connection with EOR/EGR operations. Such an approach is logical, technically 

sound, and protective of USDWs as demonstrated by decades of safe operations. 

Accordingly, EPA should amend the Proposed Rule language and expand its 

discussion in the Final Rule preamble to clarify that (a) when CO2 is injected 

for EOR and Storage, the applicable requirements are under Class II; and (b) 

when CO2 is exclusively injected for storage, the applicable requirements are 

under Class VI. 

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

HEI requests that EPA amend sections 144.3, 144.6, 144.80, 146.5 and 146.81 of 

the Proposed Rule to clarify that (a) Class II applies to EOR/EGR operations 

where geologic sequestration of CO2 is occurring during or in connection with 

EOR/EGR operations or activities (i.e. EOR and Storage); and (b) Class VI 

applies when the exclusive purpose is geologic sequestration of CO2. In addition 

to the reasons stated above, this clarity is needed because some amount of CO2 

is sequestered or stored during EOR/EGR operations regardless of the intent of 

the operator. As currently drafted, the Proposed Rule may be interpreted - 

contrary to EPA’s intent - to require EOR/EGR operations to proceed under Class 

VI. API has submitted specific language to clarify that the applicable well 

class is Class II. We support API’s proposed language modifications to sections 

44.3, 144.6, 144.80, 146.5 and 146.81 of the Proposed Rule. 

In addition, we have participated in discussions among multi-stakeholders 

including environmental groups, various associations and different industries 

(the "Multi-Stakeholder Discussions Group"); we also support the language 

recommended in the correspondence from the MSDG dated December 23, 2008 (the 

"MSDG Proposal") to sections 144.6, 144.80 and 146.5(f) establishing a "bright 

line" for wells injecting CO2 for EOR and Storage. The MSDG Proposal defines a 

"bright line" for wells that inject CO2 for EOR and Storage, and consistent with 

EPA’s intent, remain in Class II and are subject to the existing Class II 

regulations - which have adequately safeguarded USDWs in the context of EOR/EGR 

operations for decades. 

The MSDG has also agreed to continue discussions regarding specific rules that 

would be applicable to geologic sequestration of CO2 in oil and gas formations 

following the completion of EOR/EGR production. We intend to participate in 

these negotiations. The development of a subclass under Class II or Class II-B 

regulations would result in a regulatory framework that would effectively 

protect USDWs and also promote the geologic sequestration of CO2 in oil and gas 

formations, especially following the cessation of EOR/EGR production activities. 
The advantages of a subclass dedicated to geologic sequestration in oil and gas 

formations are that a Class II-B will address risks associated specifically with 

oil and gas formations, rely upon information and data gathered during the 

terminated EOR/EGR production activities and maintain permitting authority under 

a single agency with historical knowledge and expertise about the former 

operations and the receiving oil and gas formation. This would maximize the 

efficient use of administrative resources and allow for seamless transitioning 

of operations from EOR and geologic sequestration of CO2 to injection of CO2 

only for geologic sequestration. 

1 Currently, over 2 billion cubic feet of naturally-occurring CO2 is used daily 

for EOR operations and the volume is growing. 

2 Notably, it is estimated that site characterization of saline reservoirs will 

likely cost tens of millions of dollars and take years of study to permit one 

commercial scale saline storage reservoir. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. However, the Agency believes that the nature and risks of CO2 injection for the primary

purpose of long term storage poses different risks than injection for the primary purpose of EOR,

and therefore has developed new Class VI regulations to address these unique risks. For example, the

volume of CO2 anticipated to be injected for long term storage is significantly greater than for EOR

operations. Reservoir pressure conditions will also be different, with Class VI injection operations

involving large volumes of CO2 and likely having higher pressures within their storage formations

than Class II EOR projects, which may lead to fluid movement that endangers a USDW.

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 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 longterm 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.

EPA clarifies that the GS rule does not require any facilities to sequester CO2; nor does it create an

economic incentive to do so. The purpose of the GS regulation is to ensure that, where deployed, GS

is conducted in a manner that does not endanger USDWs.
Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21714

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

Same Time 

BP commends EPA for its recognition, as stated in the Preamble of the Proposed 

Rule, that oil and gas reservoirs will play a valuable role in the geologic 

storage of CO2. Two of the reasons cited by EPA are: (1) oil and gas reservoirs 

are natural storage containers that have trapped fluid (both liquid and gaseous) 

hydrocarbons for millions of years; and (2) oil and gas exploration and 

production activities have created a wealth of knowledge and geologic data that 

can support the site characterization process for geologic sequestration. (73 

Fed. Reg. at 43502-03.) Indeed, oil and gas reservoirs have proven capable of 

containing water-buoyant fluids for millions of years. These reservoirs are 

well studied and they offer the best opportunity to kick-start large-scale 

geologic sequestration of CO2, building on 100 years of oil and gas field 

operating experience. Consequently, many oil and gas reservoirs are available 

now to serve CCS projects at a commercial scale, and will add insights for 

subsequent application to other formations. 

EPA should provide further discussion and acknowledgement in its Proposed Rule 

that, when CO2 is injected for use in EOR/EGR projects, geologic sequestration 

(or long term storage) of CO2 occurs during EOR/EGR operations and continues 

after EOR/EGR operations cease ("EOR and Storage"). Furthermore, it is critical 

that EPA support and encourage geologic sequestration of CO2 in these wellstudied and proven oil and gas reservoirs by amending certain elements of the 

Proposed Rule to clarify and streamline requirements. EPA’s recognition of EOR 

and Storage will provide a much-needed near-term, economic incentive to CCS 

projects. Incentivizing the use of anthropogenic CO2 for EOR/EGR will provide 

many lasting benefits to the United States, by significantly reducing current 

CO2 emissions and increasing energy security. 

It has become increasingly clear that early EOR and Storage projects will 

significantly advance the deployment of CCS technology and geologic 

sequestration of CO2 for many reasons: 

- Oil and gas formations offer the best characterized sites among potential 

sinks for anthropogenic CO2; 

- Much of the required infrastructure and operational experience is already in 

place; 

- Class II requirements have proven to be an effective regulatory framework in 

protecting USDWs in the context of CO2 EOR operations, evidenced by more than 30 

years of experience in the Permian Basin and more than 25 years of miscible gas 

injection projects on the North Slope of Alaska (where CO2 comprises 25% of the 

miscible gas injected); 

- Demand for large volumes of CO2 for EOR is increasing [FN1]; and 
- EOR can provide a revenue stream to supplement the economics of early-mover 

CCS projects. 

EOR and Storage have the added benefit of increasing domestic energy supplies in 

the face of increasing demand. Carbon dioxide injection has proven capable of 

increasing oil or gas recovery in mature fields from 5% to more than 20%. The 

Department of Energy estimates that EOR has the potential to add 40-80 billion 

barrels of oil reserves in the United States, which is 2 to 4 times the current 

United States’s total proven reserve. The Intergovernmental Panel on Climate 

Change ("IPCC") has agreed that EOR technology can provide a significant kickstart on proving geologic sequestration of CO2 on a commercial scale. Indeed, 

the early commercial scale CCS projects will probably employ EOR and Storage as 

their basis of design, which will extensively inform the technical development 

and safe deployment of CCS projects in other types of geologic formations.[FN2] 

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

Currently, EOR/EGR operators purchase CO2 for injection. This can represent a 

significant portion of the cost of an EOR/EGR project. Consequently, CO2 is a 

valuable commodity to EOR/EGR operators and is treated accordingly. Because it 

is a valuable commodity in EOR/EGR operations, CO2 is not emitted or vented to 

the atmosphere during operations or after operations cease. Any injected CO2 

that returns to the surface during production operations is separated from the 

hydrocarbons and reinjected for additional enhanced recovery use. 

Approximately 30% to 50% of the injected CO2 volume typically remains 

permanently stored in the oil or gas reservoir after production operations 

cease. The injected CO2 is monitored in the formation and injection operations 

are designed to minimize CO2 procurement and maximize oil (and recycled CO2) 

production. Despite best efforts to re-use all the CO2, additional trapping of 

CO2 occurs with each subsequent injection cycle, necessitating further purchases 

of CO2. When the EOR operations cease (and the field is blown down to recover 

any CO2 available for use in another operation), wells are closed and the 

remainder of the injected CO2 remains permanently stored underground. However, 

an EOR operator could quite easily, at its option, manage operations to store 

the injected CO2 for the long term (rather than recover it). 

The foregoing demonstrates that, based on decades of experience gained in 

existing EOR/EGR operations utilizing CO2, EPA should acknowledge in the Final 

Rule preamble that injected CO2 can be trapped and stored for long term during 

EOR operations and continues afterwards. Furthermore, existing Class II 

regulations and industry practice employ proven methodologies to conduct these 

operations in a safe manner that is protective of USDWs. 

(2) Requested Amendments to Proposed Rule 

For the reasons stated above, EPA should expand its discussion and acknowledge 

in the Final Rule text and preamble that, when CO2 is injected for use in 

EOR/EGR projects, geologic sequestration (or long term storage) of CO2 occurs 
during EOR/EGR operations and continues after operations cease - thus EOR and 

Storage. BP supports EPA’s statement that EOR/EGR, as long as any production is 

occurring, will continue to be permitted under the Class II program. 

We also understand that it is EPA’s intent, which we strongly support, that the 

proven Class II program applies to storage of CO2 that is occurring during and 

in connection with EOR/EGR operations. Such an approach is logical, technically 

sound, and protective of USDWs as demonstrated by decades of safe operations. 

Accordingly, EPA should amend the Proposed Rule language and expand its 

discussion in the Final Rule preamble to clarify that (a) when CO2 is injected 

for EOR and Storage, the applicable requirements are under Class II; and (b) 

when CO2 is exclusively injected for storage, the applicable requirements are 

under Class VI. 

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

BP requests that EPA amend sections 144.3, 144.6, 144.80, 146.5 and 146.81 of 

the Proposed Rule to clarify that (a) Class II applies to EOR/EGR operations 

where geologic sequestration of CO2 is occurring during or in connection with 

EOR/EGR operations or activities (i.e. EOR and Storage); and (b) Class VI 

applies when the exclusive purpose is geologic sequestration of CO2. In 

addition to the reasons stated above, this clarity is needed because some 

amount of CO2 is sequestered or stored during EOR/EGR operations regardless 

of the intent of the operator. As currently drafted, the Proposed Rule may 

be interpreted - contrary to EPA’s intent - to require EOR/EGR operations to 

proceed under Class VI. API has submitted specific language BP’s Comments To 

EPA’s Proposed Rule to clarify that the applicable well class is Class II. We 

support API’s proposed language modifications to sections 144.3, 144.6, 

144.80, 146.5 and 146.81 of the Proposed Rule. 

In addition, we have participated in discussions among multi-stakeholders 

including environmental groups, various associations and different industries 

(the "Multi-Stakeholder Discussions Group"); we also support the language 

recommended in the correspondence from the MSDG dated December 23, 2008 (the 

"MSDG Proposal") to sections 144.6, 144.80 and 146.5(f) establishing a "bright 

line" for wells injecting CO2 for EOR and Storage. The MSDG Proposal defines a 

"bright line" for wells that inject CO2 for EOR and Storage, and consistent with 

EPA’s intent, remain in Class II and are subject to the existing Class II 

regulations - which have adequately safeguarded USDWs in the context of EOR/EGR 

operations for decades. 

The MSDG has also agreed to continue discussions regarding specific rules that 

would be applicable to geologic sequestration of CO2 in oil and gas formations 

following the completion of EOR/EGR production. We intend to participate in 

these negotiations. The development of a subclass under Class II or Class II-B 

regulations would result in a regulatory framework that would effectively 

protect USDWs and also promote the geologic sequestration of CO2 in oil and gas 

formations, especially following the cessation of EOR/EGR production activities. 

The advantages of a subclass dedicated to geologic sequestration in oil and gas 
formations are that a Class II-B will address risks associated specifically with 

oil and gas formations, rely upon information and data gathered during the 

terminated EOR/EGR production activities and maintain permitting authority under 

a single agency with historical knowledge and expertise about the former 

operations and the receiving oil and gas formation. This would maximize the 

efficient use of administrative resources and allow for seamless transitioning 

of operations from EOR and geologic sequestration of CO2 to injection of CO2 

only for geologic sequestration. 

[FN1] Currently, over 2 billion cubic feet of naturally-occurring CO2 is used 

daily for EOR operations and the volume is growing. 

[FN2] Notably, it is estimated that site characterization of saline reservoirs 

will likely cost tens of millions of dollars and take years of study to permit 

one commercial scale saline storage reservoir. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. However, the Agency believes that the nature and risks of CO2 injection for the primary

purpose of long term storage poses different risks than injection for the primary purpose of EOR,

and therefore has developed new Class VI regulations to address these unique risks. For example, the

volume of CO2 anticipated to be injected for long term storage is significantly greater than for EOR

operations. Reservoir pressure conditions will also be different, with Class VI injection operations

involving large volumes of CO2 and likely having higher pressures within their storage formations

than Class II EOR projects, which may lead to fluid movement that endangers a USDW.

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 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 longterm 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.

EPA clarifies that the GS rule does not require any facilities to sequester CO2; nor does it create an

economic incentive to do so. The purpose of the GS regulation is to ensure that, where deployed, GS

is conducted in a manner that does not endanger USDWs. 
Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21759

Other EPA Comment Codes and Descriptions: 1230 1.1.1.2 General comments on the regulatory

text 

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

EPA has appropriately restricted the applicability of Class VI regulations to 

projects that are exclusively geologic sequestration projects. Furthermore, BP 

appreciates EPA’s efforts to limit this rulemaking to the authority vested in 

EPA by Congress pursuant to the Safe Drinking Water Act ("SDWA"). BP requests 

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

ensure that unrelated activities in the Oil & Gas industry are not impacted by 

unintended inferences or interpretations of the Proposed Rule. 

Response: EPA clarifies that 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. For more information,

please see the discussion on transition of Class II wells in the preamble to the final GS rule.

EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the

purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. EPA also believes that the nature and risks of CO2 injection for the primary purpose of long

term storage poses different risks than injection for the primary purpose of ER, and therefore has

developed new Class VI regulations to address these unique risks. For example, the volume of CO2

anticipated to be injected for long term storage is significantly greater than for ER operations.

Reservoir pressure conditions will also be different, with Class VI injection operations involving

large volumes of CO2 and likely having higher pressures within their storage formations than Class

II ER projects.

Commenter Name: A. James Mayer Letter ID: 0230

Commenter Organization: A. J. Mayer International on behalf of the American

Energy Security Initiative

Comment ID:

21875

Comment: 4. The Proposed Rule does not recognize the benefits of injection in EOR plays. 

EPA does not consider CO2 to be sequestered following injection for EOR. Many 

CO2 sequestration projects will be associated with oil and gas operations. 

However the Proposed Rule states that sequestration begins only after enhanced 

recovery of oil or gas has stopped. The implication is that the CO2 injected for 

enhanced recovery is not ultimately sequestered upon cessation of injection and 

production activity. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS
sites. Furthermore, EPA recognizes that some portion of CO2 injected for purposes of EOR is

sequestered. However, the Agency believes that the nature and risks of CO2 injection for the primary

purpose of long term storage pose different risks than injection for the primary purpose of ER, and

therefore has developed new Class VI regulations to address these unique risks. For example, the

volume of CO2 anticipated to be injected for long term storage is significantly greater than for ER

operations. Reservoir pressure conditions will also be different, with Class VI injection operations

involving large volumes of CO2 and likely having higher pressures within their storage formations

than Class II ER projects, which may lead to fluid movement that endangers a USDW.

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 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 longterm 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.

Commenter Name: A. James Mayer Letter ID: 0230

Commenter Organization: A. J. Mayer International on behalf of the American

Energy Security Initiative

Comment ID:

21885

Comment: SPECIFIC RECOMMENDATIONS FOR IMPROVEMENTS IN THE UIC RULE 

1. EPA should create a subclass within the Class II well classification for 

operators who plan to sequester CO2 in association with enhanced recovery of oil 

or natural gas (with appropriate and necessary additional requirements to 

address any CO2 issues). 

2. Any Class VI injection well program might be applied to injection wells used 

to sequester CO2 in formations that are non-productive, such as deep saline 

formations. 

Response: The final rule does not designate a subclass under the Class II well classification. EPA

agrees that injection of CO2 for the primary purpose of enhancing oil and gas recovery should

remain under the Class II Program. However, the Agency disagrees that wells injecting CO2 for the

primary purpose of long-term storage should be regulated under Class II requirements. The Agency

believes that the nature and risks of CO2 injection for the primary purpose of long-term storage pose

different risks than injection for the primary purpose of EOR, and therefore has developed new Class
VI regulations to address these unique risks. For example, the volume of CO2 anticipated to be

injected for long-term storage is significantly greater than for EOR operations. Reservoir pressure

conditions will also be different, with Class VI injection operations involving large volumes of CO2

and likely having higher pressures within their storage formations than Class II EOR projects, which

may lead to fluid movement that endangers a USDW.

EPA clarifies that 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. For more information, please see the discussion on

transition of Class II wells in the preamble to the final GS rule.

Commenter Name: Michael E. Moore Letter ID: 0232

Commenter Organization: Blue Source Comment ID: 21896

Other EPA Comment Codes and Descriptions: 1630 1.3.3 RCRA/hazardous waste issues (seeking

comment); 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: II. Specific Comments on the Proposed Regulations 

a. Background 

Blue Source’s comments here are focused on a narrow, but critical, aspect of 

EPA’s proposal - namely, whether CO2-EOR operators should have the option of 

participating in EPA’s forthcoming CCS regulatory scheme. [FN1] 

[FN1: We believe that adoption of our comments is a necessary component of ensuring 

that CO2-EOR flourishes as CCS, but other steps need to be taken, too. For 

example, we also believe that EPA needs to ensure that carbon dioxide is not 

regulated as a hazardous waste or substance under statutes such as RCRA and 

CERCLA during storage operations; in a future rulemaking EPA perhaps could do so 

by expanding current exemptions which apply to oil & gas operations to include 

"storage" operations.] 

Response: EPA clarifies that the Class VI GS rule is designed to ensure the protection of USDWs

from endangerment, and does not aim to promote GS deployment. 

EPA notes that the GS rule is not promulgated under the RCRA or CERCLA statutes, and further,

the applicability of those statutes will not be determined under the SDWA or the terms of the GS

rule, but rather according to those statutes themselves and any implementing regulations that may

apply. 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. 

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. 

The Agency acknowledges the commenter's concerns regarding the scope and possible impacts of

CERCLA liability on CCS activities, however EPA notes that the GS rule is not promulgated under

CERCLA, therefore the applicability of that statute will not be determined under the SDWA or the

terms of the GS rule, but rather according to the CERCLA statute itself and any implementing

regulations that may apply. 

EPA adds that, if it develops regulations in the future, stakeholders will be provided opportunity for

public comment.

Commenter Name: Michael E. Moore Letter ID: 0232

Commenter Organization: Blue Source Comment ID: 21897

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: The preamble to EPA’s proposal suggests that as long as production is occurring 

and reservoirs are not depleted, Class II permitting provisions apply; only when 

a reservoir is depleted may the new proposed Class VI CCS provisions apply. 

[FN2] Because the grandfathering of the Class VI requirements is relatively 

narrow, we interpret EPA’s proposal to mean that CO2-EOR operators (and others 

associated with such projects, including industrial sources) effectively will be 

disqualified from participating in CCS. This disqualification, in turn, 

suggests that: (i) capped industrial sources who intend to use CO2-EOR as their 

means of compliance with likely forthcoming cap-and-trade legislation will be 

deprived of the ability to do so, and (ii) uncapped industrial sources under 

cap-and-trade legislation may be disqualified from seeking treatment as 

providers of offsets to regulated sources. 

[FN2: See discussion in Preamble at 48-49.] 

The inadvertent impact of EPA’s proposal is to strand CO2-EOR by not giving it 

the option of being included in CCS. This would be an unfortunate outcome for 

the environment and CCS. According to a recent study by the U.S. Department of 

Energy (DOE), CO2-EOR has the potential to provide a significant storage market 

for carbon dioxide. [FN3] DOE estimates that the size of this market is on the 

order of 7,500 million metric tons of carbon dioxide between 2008 and 2030. 
CO2-EOR, in other words, is not a niche in the battle to combat climate change; 

it instead is poised to play a critical role, particularly in the early years of 

the deployment of CCS technology. 

The commercial aspects of CO2-EOR in helping to finance, fund, and build firstmover CCS infrastructure which, in turn, could be used by broader CCS operations 

(including deep saline, for example) cannot be overlooked. DOE has estimated 

that CO2 sales for EOR would support the "early market entry" of up to fortynine (one GW size) installations of CCS technology in the coal-fired utility 

sector alone. [FN4] Given that Europe is looking at funding twelve 

demonstration CCS projects in the years ahead, we believe that forty-nine 

projects is a significant number of projects that could jump-start CCS as a 

climate mitigation solution. 

[FN3: See "Storing CO2 With Enhanced Oil Recovery," DOE/NETL-402/1312/02-0708, 

at 1 (Feb. 7, 2008) (available at 

http://www.netl.doe.gov/energy-analyses/pubs/storing%20co2%20w%20eor_final.pdf) 

.] 

[FN4 Id.] 

Giving CO2-EOR operators the option of participating in storage would not 

imperil drinking water aquifers as such assessments are already part of the 

Class II approval process. Indeed, since CO2-EOR operations are by definition 

brownfields, not greenfields, it might be expected that the risk profile of such 

projects - in terms of potential drinking water impacts - might be lower 

initially than other sites, although site assessments would of course still need 

to be done. 

Blue Source is concerned that these (and other) significant CO2-EOR benefits 

could be squandered if EPA proceeds with its proposed treatment of this proven 

technology.[FN5] 

[FN5: A large volume of literature, which won’t be repeated here, documents the 

successful, safe and environmentally sound use of CO2-EOR through the US for 

many decades. Moreover, a significant portion of US domestic oil production is 

the result of CO2-EOR: according to the 2006 EOR survey published by the Oil & 

Gas Journal, approximately 237,000 barrels per day of incremental oil production 

is being produced by eighty six CO2-EOR projects that are distributed broadly 

across the United States. CO2-EOR is not just about the Permian Basin, in other 

words.] 

b. Suggested Solution 

Blue Source encourages EPA to provide CO2-EOR operators with the option of 

participating in CCS. Such participating could take several forms. For 

example, operators (and other project participants) could be given the right to 

"opt into" what might be called an "EOR-plus" regulatory option under the 

existing Class II well program. The EOR-plus regulatory option would of course 

be limited to anthropogenic CO2 and might include the following additional 

requirements: (i) up-front suitability assessment for storage operations, 
including an analysis of the reservoir’s risk profile and an assessment of 

whether appropriate storage rights have been obtained (if necessary); and (ii) 

measuring, monitoring and verification requirements. 

This option could be selected by the operator at any time - e.g., prior to, 

during, or at the conclusion of a CO2-EOR flood. 

This option also could be implemented by the primacy States under the existing 

Class II program. This makes sense because the States already have decades of 

experience in regulating Class II; State regulators also possess the necessary 

geologic data and expertise to ensure that CO2-EOR storage operations did not 

imperil environmental end points of concern. 

In lieu of a more formalistic EOR-plus regulatory option, EPA could provide even 

greater flexibility by indicating that CO2-EOR operations would have the 

ability, on a case-by-case basis, to demonstrate that they were engaged in 

storage by meeting a performance-based storage and environmental standard, 

focused on drinking water aquifers. Alternatively, the preamble to the final 

rule could provide that the rule’s applicability was limited to deep saline, and 

that nothing in the rule was intended to impact the ability of CO2-EOR to 

qualify as storage, but that this topic would be addressed in a separate 

rulemaking, which EPA then would undertake expeditiously. 

Finally, Blue Source is not proposing that any changes be made to the existing 

Class II regulations, which would remain available for those operators who did 

not elect to opt into the EOR-plus regulatory (or comparable) scheme. Blue 

Source also is not suggesting that business-as-usual CO2-EOR qualify as storage 

because we recognize that existing Class II requirements fall short of what may 

be required to demonstrate storage. 

Conclusion 

Blue Source encourages EPA to provide CO2-EOR operators with the option of 

participating in CCS because doing so would provide the most environmentally 

sensitive method of jump-starting CCS, a critical climate mitigation technology. 

Failure of EPA to do so could stall the development, deployment and funding of 

critical CCS infrastructure and lead to unnecessary further industrial emissions 

of carbon dioxide. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. However, the Agency believes that the nature and risks of CO2 injection for the primary

purpose of long term storage poses different risks than injection for the primary purpose of ER, and

therefore has developed new Class VI regulations to address these unique risks. For example, the

volume of CO2 anticipated to be injected for long term storage is significantly greater than for ER

operations. Reservoir pressure conditions will also be different, with Class VI injection operations

involving large volumes of CO2 and likely having higher pressures within their storage formations

than Class II ER projects, which may lead to fluid movement that endangers a USDW. 

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 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 longterm 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.

EPA clarifies that the purpose of the GS rule is to ensure protection of USDWs from endangerment

and not to promote or incentivize GS deployment. However, the Agency believes that establishing a

regulatory framework for the future development and deployment of CCS technology may provide

the regulatory and jurisdictional certainty needed to foster development and deployment of CCS

while ensuring USDW protection.

Commenter Name: M. Granger Morgan Letter ID: 0233

Commenter Organization: Carnegie Mellon University on behalf of the CCS

Reg Project

Comment ID:

21902

Comment: 11. To prevent creation of an overly inhibitive regulatory framework, the UIC 

program should continue to permit wells injecting CO2 under existing well 

classes and/or the proposed Class VI rules, for a limited and defined period. 

Concurrently, a Commission or an Interagency Task Force (established either 

through legislation or executive order of the President) should gather and 

synthesize results from pilot and early commercial-scale projects, providing 

recommendations to Congress on the proper format to regulate widespread 

commercial CCS. Chapter 11 of the attached report details this two-stage 

approach [SEE PDF TO VIEW THE REPORT].

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS. 

The Agency is using an adaptive approach to regulate GS injection. EPA will collect and review

project data on early GS projects, including pilot projects, to determine whether the appropriate

amount and types of information and documentation are being collected. EPA plans, every six years,

to collect and review data on GS projects to determine whether the appropriate amount and types of
information and appropriate documentation are being collected, and to determine if modifications to

the requirements are appropriate or necessary. EPA does not plan to establish a task force for this

purpose, however.

Commenter Name: M. Granger Morgan Letter ID: 0233

Commenter Organization: Carnegie Mellon University on behalf of the CCS

Reg Project

Comment ID:

21909

Comment: 18. Relationship between Class VI Wells and Class II Wells: Regulations for GS 

site permitting should create a clear path by which CO2-flood enhanced oil 

recovery (EOR) projects permitted as UIC Class II wells, can become commercial 

sequestration projects under new regulations. The risk profile at a site 

operated for EOR will change when the site transitions to GS as different 

stresses are placed on wells and geologic formations. The Class VI rules should 

provide more specific and comprehensive guidance on how an operator must 

demonstrate that a Class II site can safely contain injected CO2 as a commercial 

sequestration project. The proposed Class VI rules lay the groundwork, by 

providing the Director with discretion to "grandfather" only the construction 

requirements for existing Class I and Class II wells seeking a permit for GS 

(provided he/she is able to make a determination that these wells would not 

endanger USDWs) and requiring operators to meet all other requirements of the 

proposed rule. However, additional conditions are needed, such as: 

• Establishment of monitoring and reporting requirements for EOR sites that wish 

to be eligible for crossover; 

• Specification of the technical requirements for an operator to demonstrate 

that a Class II well could be reclassified as a Class VI well; and 

• Much of the data for EOR projects is currently proprietary. The rule should 

address what types of data must be made public for EOR sites that wish to be 

eligible for crossover. 

Similar clarifications are needed for pilot and early-mover projects permitted 

as UIC Class V wells which later might be converted to commercial sequestration 

projects. 

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 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 the transition of Class II wells in the preamble to the final GS rule.

EPA agrees that Class II wells are designed and constructed to withstand exposure to CO2. The final

GS rule allows the construction of these wells to be grandfathered per §146.81(c), provided the

owner or operator can demonstrate to the Director that the wells were engineered and constructed to

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

§146.86(b) and §146.87(a).

EPA clarifies that monitoring and reporting requirements for all GS projects are described in

§146.90. This section requires owners or operators to develop a site-specific monitoring and testing

plan and submit it along with the permit application.

Commenter Name: Abbie Krebsbach Letter ID: 0235

Commenter Organization: Montana-Dakota Utilities Co. Comment ID: 23178

Comment: Potential Obstruction of Enhanced Oil Recovery (EOR) Activities 

EPA's search for a regulatory structure to manage geologic sequestration of CO2, 

in the context of CO2 capture initiatives contemplated in CCS initiatives, has 

resulted in this proposal to create a new SDWA UIC "Class VI" category. This 

effort reflects the fact that geologic sequestration wells do not fall neatly 

into any of the current SWDA UIC classes. Montana-Dakota understands that 

rationale and generally supports the distinction being drawn. In fact, MontanaDakota wants to make sure that the distinction is drawn clearly enough that it 

does not confuse or impede the existing CO2 uses, such as enhanced oil recovery 

(EOR), already covered under Class II of the UIC regime. 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. The GS rule contains tailored requirements for the permitting, geologic site

characterization, AoR and corrective action, well construction, operation, mechanical integrity

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that directly

address issues unique to the nature of large-scale CO2 injection for GS. 

EPA clarifies that projects that inject CO2 for the primary purpose of long-term storage will be

permitted as Class VI wells and will be subject to the specific requirements in the final GS rule. The

GS rule contains tailored requirements that directly address issues unique to large-scale CO2

injection for GS.

In response to the comment that establishing a new well class will create economic and operational

barriers, EPA clarifies that this comment is outside the scope of this rulemaking. The purpose of the

GS rule is to ensure protection of USDWs from endangerment and not to promote or incentivize GS

deployment. Howver, the Agency believes that establishing a regulatory framework for the future

development and deployment of CCS technology may provide the regulatory and jurisdictional

certainty needed to foster development and deployment of CCS while ensuring USDW protection.
Commenter Name: Angie Burckhalter Letter ID: 0239

Commenter Organization: Oklahoma Independent Petroleum Association Comment ID: 23213

Comment: Carbon dioxide has been used by the oil and gas industry in enhanced oil 

recovery (EOR) projects in a safe and effective manner for over 35 years which 

has contributed to increased American oil production. EPA should ensure its 

proposed rule does not negatively impact or impede the use of CO2 in Class II 

EOR projects or the disposal of CO2 and other fluids that are generated in the 

production of oil and gas into Class II wells that are currently regulated. 

Under Part II, item G of the proposed rule, EPA states that if finalized, the 

proposed requirements "...would not specifically (emphasis added) apply to Class 

II injection wells..." We think EPA needs to clearly state that these activities 

are exempt from EPA’s proposed rule so that our industry can continue to 

effectively produce American oil resources. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. However, the Agency disagrees that wells

injecting CO2 for the primary purpose of long term storage should be regulated under Class II

requirements because Class II requirements are not adequate to address the unique risks associated

with long term storage of CO2 while ensuring the protection of USDWs from endangerment. 

EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the

purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. Furthermore, EPA also recognizes that a by-product of ER activities is that a certain percentage

of the CO2 is trapped in the receiving formation. However, the Agency believes that the nature and

risks of CO2 injection for the primary purpose of long term storage poses different risks than

injection for the primary purpose of ER, and therefore has developed new Class VI regulations to

address these unique risks. For example, the volume of CO2 anticipated to be injected for long term

storage is significantly greater than for EOR operations. Reservoir pressure conditions will also be

different, with Class VI injection operations involving large volumes of CO2 and likely having

higher pressures within their storage formations than Class II EOR projects, which may lead to fluid

movement that endangers a USDW.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23224

Comment: 2. Injection of CO2 for the purposes of enhanced oil and gas recovery (EOR/EGR), 

as long as any production is occurring, will continue to be permitted under the 

Class II program. EPA seeks comment on the merits of this approach since owners 

or operators of some Class II EOR/EGR wells may wish to use wells for the 

purposes of production and GS prior to the field being completely depleted. EPA 

Notice 43502. 

This approach makes the most sense since enhanced recovery operations have 

proven successful at increasing and maximizing oil and gas recovery while 

successfully sequestering carbon dioxide. As long as production of oil and gas 

is occurring, it would be inefficient and confusing to change the rules and 

processes under which these wells are regulated. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas
recovery should remain under the Class II Program. The Agency believes that the nature and risks of

CO2 injection for the primary purpose of long term storage poses different risks than injection for

the primary purpose of EOR, and therefore has developed new Class VI regulations to address these

unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is

significantly greater than for EOR operations. Reservoir pressure conditions will also be different,

with Class VI injection operations involving large volumes of CO2 and likely having higher

pressures within their storage formations than Class II EOR projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary

purpose of long term storage obtain a Class VI permit with some special consideration for the fact

that they are transitioning from a well not originally designed to meet Class VI requirements. The

Director has the authority to determine at what point a Class VI permit is required for those projects

that are transitioning from the primary purpose of EOR to long term storage of CO2. The final

regulation provides a set of technical factors for the Director to evaluate in making this

determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs

when there is an increased risk to USDWs as compared to traditional Class II operations while

allowing for site-specific flexibility. 

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 longterm 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.

Commenter Name: Lori Wrotenbery Letter ID: 0247

Commenter Organization: Oklahoma Corporation Commission Comment ID: 22234

Comment: The division supports the efforts of various groups filing comments on the 

proposal to ensure that enhanced oil and gas recovery projects continue to 

operate under the current, well-established and highly effective Class II UIC 

regulatory program. The division also supports efforts to develop a regulatory 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. The Agency believes that the nature and risks of

CO2 injection for the primary purpose of long term storage poses different risks than injection for

the primary purpose of EOR, and therefore has developed new Class VI regulations to address these

unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is

significantly greater than for EOR operations. Reservoir pressure conditions will also be different,

with Class VI injection operations involving large volumes of CO2 and likely having higher

pressures within their storage formations than Class II EOR projects.

Commenter Name: James T. Sims Letter ID: 0249

Commenter Organization: Western Business Roundtable Comment ID: 22259

Other EPA Comment Codes and Descriptions: 2020 1.5.1 Support Class VI designation 

Comment: 1. Don’t Chill On-Going Enhanced Oil Recovery (EOR) Activities -- EPA’s search 
for a regulatory structure to manage geologic sequestration of CO2, in the 

context of CO2 capture initiatives contemplated in CCS initiatives, has resulted 

in this proposal to create a new SDWA UIC "Class VI" category . This effort 

reflects the fact that geologic sequestration wells do not fall neatly into any 

of the current SWDA UIC classes. We understand that rationale and generally 

support the distinction being drawn. In fact, we want to make sure that the 

distinction is drawn clearly enough that it doesn’t confuse or impede the 

existing CO2 uses, such as EOR, already covered under Class II of the UIC 

regime. 

Response: EPA believes that injection for the primary purpose of long-term storage is sufficiently

different from Class II EOR operations and warrants tailored requirements. EPA agrees that the

nature and risks of CO2 injection for long-term storage is different from Class II CO2 injection for

EOR, and that tailored requirements for GS wells are appropriate and necessary to protect USDWs

from endangerment. For this reason, the Agency tailored UIC requirements for Class VI wells that

address the general risks deep injection may pose to USDWs and specifically address the unique

nature of CO2 GS (i.e., very large volumes, very long time-periods, and reservoir pressure

conditions). 

EPA clarifies that the purpose of the GS rule is not to incentivize or encourage the use of GS or to

address the use of pore space. The purpose of the GS rule is to ensure that, where GS is deployed, it

is conducted in a manner that does not endanger USDWs. 

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24835

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: The GWPC also recommends EPA consider retaining all geologic sequestration in 

oil and gas reservoirs under the jurisdiction of Class II UIC programs and 

create a subclass within this program for geologic storage of carbon dioxide. 

This subclass (Class II GS) would be used for those wells that depart from the 

traditional uses of Class II wells for enhanced recovery, and result in the 

application of Class VI standards. This change would eliminate any confusion 

over whether a Class II CO2 injection well used for enhanced recovery might also 

need a Class VI permit and would avoid the need to change jurisdiction for a 

well from one state agency to another over time. 

Response: EPA disagrees that the risks posed by long term storage of CO2 for GS can be addressed
under existing UIC requirements, such as those for Class II wells. EPA believes and the

administrative record supports that there are significant differences between how EOR and GS

projects are operated, as well as the different risks posed by these different injection activities. The

new tailored approach of the GS rule was designed to address the general risks deep injection may

pose to USDWs and was tailored specifically to address the risks posed by long term storage of CO2

(i.e., very large volumes, very long time-periods, and reservoir pressure conditions).

In response to the comment on the burden of changing regulatory agencies in the middle of an

operation, EPA clarifies that primacy is granted to a state, not to a specific agency within that state,

and states may choose which agency implements the Class VI program. States may, for example,

choose an environmental quality protection agency (non-Class II) or the state's traditional oil and gas

regulatory agency to implement the Class VI program as long as the program meets the minimum

federal requirements for Class VI wells as required under section 1422 of SDWA. Some states

manage all injection well classes under Section 1422 and through a single agency, while in other

states, Class II programs are run by oil and gas agencies. 

Regardless of the specific Agency the state selects to assume regulatory authority for Class VI

operations, the state must obtain primacy for the 1422 Class VI program. Furthermore, the state may

determine that a memorandum of understanding (MOU) between several state agencies regarding

specific projects can facilitate this process without needing to change regulatory agencies after Class

II projects have transitioned to a Class VI permit.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24846

Comment: The GWPC also recommends EPA consider retaining all geologic sequestration in 

oil and gas reservoirs under the jurisdiction of Class II UIC programs and 

create a subclass within this program for geologic storage of carbon dioxide. 

This subclass (Class II GS) would be used for those wells that depart from the 

traditional uses of Class II wells for enhanced recovery, and result in the 

application of Class VI standards. This change would eliminate any confusion 

over whether a Class II CO2 injection well used for enhanced recovery might also 

need a Class VI permit and would avoid the need to change jurisdiction for a 

well from one state agency to another over time. 

Response: EPA disagrees that the risks posed by long term storage of CO2 for GS can be addressed

under existing UIC requirements, such as those for Class II wells. EPA believes and the

administrative record supports that there are significant differences between how EOR and GS

projects are operated, as well as the different risks posed by these different injection activities. The

new tailored approach of the GS rule was designed to address the general risks deep injection may

pose to USDWs and was tailored specifically to address the risks posed by long term storage of CO2

(i.e., very large volumes, very long time-periods, and reservoir pressure conditions).

In response to the comment on the burden of changing regulatory agencies in the middle of an

operation, EPA clarifies that primacy is granted to a state, not to a specific agency within that state,

and states may choose which agency implements the Class VI program. States may, for example,

choose an environmental quality protection agency (non-Class II) or the state's traditional oil and gas

regulatory agency to implement the Class VI program as long as the program meets the minimum

federal requirements for Class VI wells as required under section 1422 of SDWA. Some states

manage all injection well classes under Section 1422 and through a single agency, while in other
states, Class II programs are run by oil and gas agencies. 

Regardless of the specific Agency the state selects to assume regulatory authority for Class VI

operations, the state must obtain primacy for the 1422 Class VI program. Furthermore, the state may

determine that a memorandum of understanding (MOU) between several state agencies regarding

specific projects can facilitate this process without needing to change regulatory agencies after Class

II projects have transitioned to a Class VI permit. 

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24850

Comment: The GWPC also recommends EPA consider retaining all geologic sequestration in 

oil and gas reservoirs under the jurisdiction of Class II UIC programs and 

create a subclass within this program for geologic storage of carbon dioxide. 

This subclass (Class II GS) would be used for those wells that depart from the 

traditional uses of Class II wells for enhanced recovery, and result in the 

application of Class VI standards. This change would eliminate any confusion 

over whether a Class II CO2 injection well used for enhanced recovery might also 

need a Class VI permit and would avoid the need to change jurisdiction for a 

well from one state agency to another over time. 

Response: EPA disagrees that the risks posed by long term storage of CO2 for GS can be addressed

under existing UIC requirements, such as those for Class II wells. EPA believes and the

administrative record supports that there are significant differences between how EOR and GS

projects are operated, as well as the different risks posed by these different injection activities. The

new tailored approach of the GS rule was designed to address the general risks deep injection may

pose to USDWs and was tailored specifically to address the risks posed by long term storage of CO2

(i.e., very large volumes, very long time-periods, and reservoir pressure conditions).

In response to the comment on the burden of changing regulatory agencies in the middle of an

operation, EPA clarifies that primacy is granted to a state, not to a specific agency within that state,

and states may choose which agency implements the Class VI program. States may, for example,

choose an environmental quality protection agency (non-Class II) or the state's traditional oil and gas

regulatory agency to implement the Class VI program as long as the program meets the minimum

federal requirements for Class VI wells as required under section 1422 of SDWA. Some states

manage all injection well classes under Section 1422 and through a single agency, while in other

states, Class II programs are run by oil and gas agencies. 

Regardless of the specific Agency the state selects to assume regulatory authority for Class VI

operations, the state must obtain primacy for the 1422 Class VI program. Furthermore, the state may

determine that a memorandum of understanding (MOU) between several state agencies regarding

specific projects can facilitate this process without needing to change regulatory agencies after Class

II projects have transitioned to a Class VI permit. 

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24964

Comment: Rule Provision: 144.80 

EPA Proposal: 11. Section 144.80 is amended by revising the first sentence in 
paragraph (e) and by adding paragraph (f)to read as follows: 

§ 144.80 What is a Class V injection well? * * * * * 

(e) Class V. Injection wells not included in Class I, II, III, IV or VI. * * 

* 

(f) Class VI. Wells used for geologic sequestration of carbon dioxide. 

GWPC Recommendations: (4) For enhanced recovery of oil or natural gas where 

geologic sequestration is occurring during or in connection with enhanced 

recovery of oil or natural gas provided (i) there is reasonable expectation of 

more than insignificant future production volumes or rates as a result of carbon 

dioxide injection and (ii) operating pressures are no higher than reasonably 

necessary to produce such volumes or rates; 

Response: EPA disagrees with the suggested changes to the rule language; geologic sequestration

conducted as part of enhanced recovery operations is considered Class II. Injection where geologic

sequestration is the primary purpose is categorized as Class VI.

Commenter Name: Craig Hart Letter ID: 0261

Commenter Organization: Alston & Bird LLP Comment ID: 22986

Comment: Although the EPA issued guidance that applications for CCS injections should be 

submitted under the SDWA UIC program's Class V experimental well category,[FN4] a 

survey of 19 of the 24 geologic sequestration Phase II projects for which data 

was available shows that almost two-thirds of the permits will be issued under 

Class II for EOR/EGR activities. 

Interviews with the Phase II project lead organizations revealed that decisions 

concerning what class of UIC permit would be pursued were typically based on the 

type of activity most closely associated with the injection (e.g., EOR/EGR) and 

the recommendations of partners and the government agencies issuing the injection 

permits. Interviewees commonly cited greater experience with CO2 injection under 

EOR/EGRrelated Class II permits and the perception that Class II permits are 

easier to obtain compared to Class V permits as the reasons for pursuing permits 

under Class II. 

Phase II Project Wells by Formation Type and UIC Class 

[SEE EPA-HQ-OW-2008-0390-0261.PDF FOR TABLE] 

Note: The survey includes the WESTCARB Calpine-Rosetta project as it was 

originally planned before its cancellation. As planned, it would involve two 

injections at different levels in a stacked saline aquifer and gas field, 

requiring two permits, for a total of 20 permits for the 19 projects surveyed. 

[FN4] U.S. Environmental Protection Agency, DIC Program Guidance No. 83, "Using 

the Class V Experimental Technology Well Classification for Pilot Geologic 

Sequestration Projects," March 1, 2007, available at http://www.epa.gov/ 
safewater/uic/pdfs/ guide_uic_carbonsequestrationjinal-O307.pdf. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. Furthermore, EPA believes that injection of CO2 for the primary purpose of enhancing oil and

gas recovery should remain under the Class II Program. However, the Agency believes that the

nature and risks of CO2 injection for the primary purpose of long term storage poses different risks

than injection for the primary purpose of ER, and therefore has developed new Class VI regulations

to address these unique risks. For example, the volume of CO2 anticipated to be injected for long

term storage is significantly greater than for ER operations. Reservoir pressure conditions will also

be different, with Class VI injection operations involving large volumes of CO2 and likely having

higher pressures within their storage formations than Class II ER projects. 

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 longterm 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.

Commenter Name: Dianna Tickner Letter ID: 0262

Commenter Organization: Peabody Energy Comment ID: 22992

Comment: rule. The rule should also provide more certainty and flexibility to convert 

Class II EOR wells to permanent CO2 storage wells. As proposed, the site geology 

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 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 longterm storage of large volumes of CO2. The guidance describes the 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: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22790

Comment: II. G. How Would This Proposal Affect Existing Injection Wells Under the UIC

Program? 

B. EPA seeks comment on the merits of this approach since owners or operators 

of some Class II EOR/EGR wells may wish to use wells for the purposes of production 

and GS prior to the field being completely depleted. 

IOGCC Response: The IOGCC agrees with EPA's proposed approach as long as the 

project is an EOR project under Class II and the operator has been able to 

demonstrate viable production. EPA should consider a separate classification 

other than the proposed Class VI, as well as requisite requirements, for wells 

that are transitioned from Class II EOR to Class II related storage. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. However, the Agency believes that the nature

and risks of CO2 injection for the primary purpose of long term storage poses different risks than

injection for the primary purpose of ER, and therefore has developed new Class VI regulations to

address these unique risks. For example, the volume of CO2 anticipated to be injected for long term

storage is significantly greater than for ER operations. Reservoir pressure conditions will also be

different, with Class VI injection operations involving large volumes of CO2 and likely having

higher pressures within their storage formations than Class II ER projects. 

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 longterm storage of large volumes of CO2. The guidance describes the 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.

Commenter Name: Michael Moore Letter ID: 0265

Commenter Organization: North American Carbon Capture & Storage

Association (NACCSA)

Comment ID:

22859

Comment: - Other Issues for the Agency's Consideration: The Agency should ensure that 

nothing in the rule precludes CO2-EOR operators from claiming "storage" at some 

future date. Additionally, NACCSA notes that because of the Agency's limited 

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

EPA clarifies that carbon storage credits are outside the scope of the GS rulemaking.

Commenter Name: Michael Moore Letter ID: 0265

Commenter Organization: North American Carbon Capture & Storage

Association (NACCSA)

Comment ID:

22873

Comment: 10. Other Issues for the Agency's Consideration 

One additional issue raised in the Preamble relates to treatment of injection 

wells that are currently producing oil or gas. The Preamble suggests that as long 

as production is occurring and the reservoirs are not depleted, Class II 

permitting provisions apply; only when a reservoir is depleted may Class VI 

provisions apply.[FN2] NACCSA encourages the Agency to consider regulatory or 

preamble language in the final rule which clarifies that nothing in the rule is 

intended to preclude CO2-EOR operators for claiming that they are engaged in 

"storage" operations for purposes (for example) of a future cap-and-trade scheme. 

[FN2] See discussion in Preamble at 48-49. 

Response: EPA clarifies that 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. For more information,

please see the discussion on transition of Class II wells in the preamble to the final GS rule.

EPA clarifies that cap and trade legislation is outside the scope of the GS rulemaking.

Commenter Name: Grover Campbell Letter ID: 0271

Commenter Organization: Chesapeake Energy Comment ID: 22892

Comment: The primary focus of our comments is that additional language is needed in the 

proposed rule to clarify that existing and future Class II wells used for 

underground injection of naturally occurring acid gases, including CO2, at gas 

production and/or gas processing sites are exempted from regulation under the 

new Class VI well designation. 

1 . Exemption of Class II Wells from the proposed Class VI Well Classification 

Section G of the Preamble to the proposed rule (G. How Would This Proposal 

Affect Existing Injection Wells Under the U1C Program?) reads in part: "The 

requirements in today's proposal, if finalized, would not specifically apply to 

Class II injection wells. . ." Other statements in the preamble suggest that the 
EPA's intent is to not regulate existing or future Class II wells as Class VI 

wells unless an owner or operator of such a well chooses to reclassify the well 

for geologic sequestration of a CO2 stream. However, the applicability language 

and definitions in the proposed rule do not achieve that goal. More specific 

language is needed in order for the public, regulatory agencies and courts to 

know without a doubt that Class II wells used for underground injection of 

naturally occurring acid gases, including CO2, at gas production and/or gas 

processing sites are exempt from the Class VI requirements. The same applies for 

CO2 injection wells at Enhanced Oil or Gas Recovery (EOR/EGR) field operations . 

Therefore, the following language revisions should be made. 

Revise 40 CFR Part 144 Subpart H, 146.81(b) to read: 

This subpart applies to wells used to inject carbon dioxide specifically for the 

purpose of geologic sequestration, i.e., the long-term containment of a gaseous, 

liquid or supercritical carbon dioxide stream in subsurface geologic formations. 

(1) Unless applicability is requested by the owner or operator, existing 

and future Class II wells that inject CO2 and other fluids, which are brought to 

the surface in connection with conventional oil or natural gas production 

operations, are exempt from the requirements of this subpart. 

(2) Unless applicability is requested by the owner or operator, existing 

and future Class 11 wells that inject CO2 and other fluids, which are operated in 

connection with an Enhanced Oil or Gas Recovery (EOR/EGR) field operation, are 

exempt from the requirements of this subpart. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. The Agency believes that the nature and risks of

CO2 injection for the primary purpose of long term storage pose different risks than injection for the

primary purpose of EOR, and therefore has developed new Class VI regulations to address these

unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is

significantly greater than for EOR operations. Reservoir pressure conditions will also be different,

with Class VI injection operations involving large volumes of CO2 and likely having higher

pressures within their storage formations than Class II EOR projects.

The GS rule language, at §146.81(b), clearly states that the rule applies to wells that inject carbon

dioxide for the purpose of long term sequestration. Wells that inject carbon dioxide primarily for the

purpose of enhanced recovery or oil or gas are considered Class II wells, and they are not required to

meet the requirements in the final GS rule.

Commenter Name: David Hawkins Letter ID: 0272

Commenter Organization: Natural Resources Defense Council Comment ID: 24077

Comment: Sequestration in hydrocarbon reservoirs 

We also wish to comment on the distinction between a Class II EOR project and 

sequestration in oilfields. Currently, EOR operators purchase CO2 for injection 

at an expense. Consequently, CO2 is a valuable commodity to EOR operators and is 

treated accordingly. CO2 purchases from natural, and, to a lesser extent, 
anthropogenic sources, represent a major cost to a CO2-EOR operation, often as 

high as 50% of overall project costs. As such, operators have had a strong 

incentive to minimize the amount of CO2 purchased and injected, and frequently 

have relied on the injection of water alongside the CO2 in a process known as 

Water-Alternating-Gas (WAG). To minimize the amount of CO2 purchased, CO2 is not 

intentionally emitted or vented to the atmosphere during operations or after 

operations cease. Any injected CO2 that returns to the surface during production 

operations is separated from the hydrocarbons and re-injected for additional 

enhanced recovery use. Approximately 30% to 50% of the injected CO2 volume 

typically remains in the oil or gas reservoir after production operations cease. 

However, this current economic rationale for recycling CO2 does not assure longterm retention of the injected CO2 for several reasons and thus does not provide 

a basis for assuming that either "business as usual" EOR activities or EOR 

activities modified to increase amounts of CO2 injected should qualify as GS, 

without additional showings and regulatory requirements. Accordingly, no wells 

permitted only under Class II rules as they now stand should be treated as GS 

activities. 

Long-term retention of injected CO2 in Class II wells is not assured, first, 

because current recycling activities are based on economic incentives that can 

change as the market price for purchasing CO2 changes. Second, the economic 

incentive to prevent leaks ends when CO2 purchases for additional production 

ceases. Third, the fields where EOR is being practiced were not selected 

specifically for their suitability for long-term CO2 retention and were not 

subject to any regulatory screening to assess such suitability. Fourth, in a 

carbon constrained-world, where there is an economic incentive to maximize the 

amount of CO2 injected in oilfields, additional injection could lead to a change 

in the risk profile to USDWs that exceeds common practice of Class II operations 

to date. Current Class II operations have no real reason or incentive to exceed 

the original reservoir pressure in the oilfield: the resulting pressure drop 

after primary recovery is only partly compensated for or equaled during 

secondary and tertiary recovery. Exceeding original reservoir pressure could 

lead to conditions that are closer to or exceed the tensile or shear fracture 

limits of the reservoir or fault slippage pressures. The additional pressure 

could also affect a given caprock’s ability to prevent CO2 or other reservoir 

fluid leakage through it, as pressure approaches or exceeds the capillary entry 

pressure for the caprock. Finally, the larger volumes of CO2 injected could lead 

to CO2 or reservoir fluids approaching of breaching spill points in the 

reservoir, and/or a greater volume of displaced fluids and a larger area of 

elevated pressure. 

Similar considerations prevent wells regulated under other existing UIC 

classifications from being treated as GS activities. 

For all of these reasons, we oppose any approach that allows wells that are not 

subject to the necessary requirements to be defined and treated as GS 

activities. All CO2 injection activities that are treated under EPA rules as GS 

projects to protect USDWs and to prevent releases to the atmosphere, whether 

conducted solely for GS purposes or for additional purposes, must be reviewed 
and permitted pursuant to adequate rules set forth for those injection 

activities. EPA should promulgate such rules under the current rulemaking for 

Class VI, taking into account differences in target reservoir types as needed. 

Response: EPA believes that injection for the primary purpose of long term storage is sufficiently

different from Class II ER operations and warrants tailored requirements in order to protect USDWs

from endangerment. For example, the volume of CO2 anticipated to be injected in Class VI wells is

significantly greater than for Class II wells. Reservoir pressure conditions will also be different, with

Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II ER projects, which may lead to fluid movement that

endangers a USDW. 

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 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 longterm 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.

The purpose of this rule is not to promote or incentivize the deployment of GS.

Commenter Name: Jimmy Carlile Letter ID: 0281

Commenter Organization: Fasken Oil & Ranch Comment ID: 24114

Comment: proposed rules concerning geologic sequestration of carbon dioxide. Our primary 

concern with these proposed regulations is that the oil industry be able to 

continue to fully utilize carbon dioxide in a way that is beneficial to the 

global environment and both our nation's economy and its energy security through 

enhanced oil recovery (EOR) technology. Injection of carbon dioxide through 

existing SDWA Class II injection wells is crucial in the ultimate recovery of 

oil reserves throughout our industry. Proposed new SDWA "Class VI" injection 

wells for commercial carbon dioxide capture and sequestration need to be clearly 

defined to exclude EOR technologies used by the oil industry as these 

technologies are significantly different in their intent and nature. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA also recognizes that the oil and gas
industry has decades of experience injecting CO2 for the purpose of ER, and that sites used for ER

may be suitable for GS and may be among the first GS sites.

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

EPA adds that the purpose of the GS regulation is not to promote GS or address energy security;

rather the purpose of the GS regulation is to ensure that GS is conducted in a manner that protects

USDWs from endangerment.

Commenter Name: Kyle Isakower Letter ID: 0289

Commenter Organization: American Petroleum Institute Comment ID: 25276

Comment: year. In the December 23 letter, the stakeholders described the agreement to 

include in Class II a classification (b)(4) that establishes a "bright line" 

definition for wells that inject CO2 for EOR/EGR and GS. The participating 

stakeholders agree that this approach is preferable to the approach in the 

proposed rule and recommended, consistent with EPA’s intent, that these wells 

should remain in Class II and be subject to the current requirements of Class 

II. We also agreed that wells used for GS in oil and gas reservoirs that do not 

meet the criteria of (b)(4) should be subject to additional requirements beyond 

current Class II requirements. That letter noted agreement to define such wells 

as wells used "for geologic sequestration in oil and gas formations and where 

the criteria of paragraph (b)(4) are not met." In our discussions since 

December, we have agreed that these wells should be regulated in a separate 

class or subclass, and we recommend that the Agency include in its plans for 

both publication of a NODA and the final rule the approach of regulating these 

wells used for GS in oil and gas reservoirs under a separate classification. We 

are still committed to and making progress in our multi-stakeholder discussions 

toward developing recommendations on the specific requirements that should be 

applied to this category of wells. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. However, EPA believes that there are significant

differences between how EOR and GS projects are operated, as well as the different risks posed by

these different injection activities. The new tailored approach of the GS rule was designed to address

the general risks deep injection may pose to USDWs and was tailored specifically to address the

risks posed by long term storage of CO2 (i.e., very large volumes, very long time-periods, and

reservoir pressure conditions).

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 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 longterm 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.

Commenter Name: Kyle Isakower Letter ID: 0290

Commenter Organization: American Petroleum Institute Comment ID: 25281

Comment: In our discussions since then, MSG participants have agreed that these wells 

used for GS in oil and gas reservoirs should be subject to a set of requirements 

different from those that would apply under the current Class II provisions to 

wells that inject CO2 for EOR/EGR and GS, due to the potential change in the 

risk profile when EOR/EGR activities cease. This common view is reflected in the 

four letters you received on March 17 from MSG participants. Each of these 

letters asks EPA to include this approach in its final GS rule. The MSG has also 

discussed the desirability for EPA to take advantage of the opportunity to 

publish proposed regulations for this category of wells for public review and 

comment in conjunction with a NODA, allowing others to address this 

recommendation in responding to the NODA. That discussion is also reflected in 

several of the March 17 letters. To that end, the signatories to this letter 

submit the language in Attachment A with the request that EPA include in its 

NODA a request for public comment on these proposed requirements. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA also recognizes that the oil and gas

industry has decades of experience injecting CO2 for the purpose of EOR, and that sites used for

EOR may be suitable for GS and may be among the first GS sites. However, EPA believes that

injection for the primary purpose of long term storage is sufficiently different from Class II EOR

operations and warrants tailored requirements. For example, the volume of CO2 anticipated to be

injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure

conditions will also be different, with Class VI injection operations involving large volumes of CO2

and likely having higher pressures within their storage formations than Class II EOR projects. 

Commenter Name: Kyle Isakower Letter ID: 0290

Commenter Organization: American Petroleum Institute Comment ID: 25282

Comment: The undersigned recommend that the requirements in Attachment A be added to 
Class II through an amendment to add a new section 146.25, as shown. The MSG 

discussions, however, have also considered that these requirements could be 

promulgated as a new Class VII in a new Part 146, Subpart I. To acknowledge 

those discussions and to provide EPA with a basis for seeking comment on that 

alternative approach, this letter also addresses that alternative. 

[In the section below, the text in all CAPS denotes added text. For redline 

strikeout version of this attachment see PDF Docket ID EPA-HQOW-2008-0390-0290.] 

The Class II Approach 

In conjunction with the requirements proposed in Attachment A, the addition of 

these requirements as section 146.25 should be accompanied by the addition of 

the word "and" at the end of paragraphs 144.5(b)(4), 144.80(b)(4) and 146.5(b) 

(4) as proposed in the December 23 MSG letter and the addition of a new 

paragraph (5) in subsections 144.5(b), 144.80(b) and 146.5(b) reading: 

(5) For geologic sequestration in oil and gas formations and where the 

criteria of paragraph (b)(4) are not met. 

And subsections 144.5(f), 144.80(f) and 146.5(f) should be revised to read as 

follows: 

(f) Class VI. Wells INJECTING A CARBON DIOXIDE STREAM FOR GEOLOGIC 

SEQUESTRATION EXCEPT THOSE WELLS DESCRIBED IN PARAGRAPHS (B)(4) AND (B) 

(5) OF THIS SECTION OR OTHERWISE EXCLUDED FROM THIS CLASS. 

The Class VII Approach 

Alternatively, if a new Class VII were created, a new subsection (g) could be 

added to sections 144.5, 144.80 and 146.5 as follows: 

(g) Class VII. Wells injecting a carbon dioxide stream for geologic 

sequestration in oil and gas formations and where the criteria of 

paragraph (b)(4) are not met. 

And subsections 144.5(f), 144.80(f) and 146.5(f) should be revised to read as 

follows: 

(f) Class VI. Wells INJECTING A CARBON DIOXIDE STREAM FOR GEOLOGIC 

SEQUESTRATION EXCEPT THOSE WELLS DESCRIBED IN SUBSECTIONS (B)(4) AND (G) 

OF THIS SECTION OR OTHERWISE EXCLUDED FROM THIS CLASS. 

Response: As described above, EPA agrees that injection of CO2 for the primary purpose of

enhancing oil and gas recovery should remain under the Class II Program, but that there are

significant differences between how ER and GS projects are operated. EPA disagrees that the

creation of a Class VII well category for GS that occurs in oil and gas formations is necessary

because the Class VI requirements are appropriate for GS in all formations. For more information,

please see the discussion on transition of Class II wells in the preamble to the final GS rule.
Commenter Name: Kyle Isakower Letter ID: 0290

Commenter Organization: American Petroleum Institute Comment ID: 25284

Comment: The undersigned submit these recommendations with the request that the 

recommendations be published as a basis for seeking public comment on this 

approach and the related issues in conjunction with any NODA that is published. 

In addition, we are committed to continuing the MSG discussions with an 

objective of developing additional specific recommendations for improvement of a 

final rule that could be adopted, consistent with your previously published 

schedule, by late 2010 or early 2011 or sooner. 

As noted in the December 23, 2008 letter, the consensus recommendations 

presented in this letter are solely for the purpose of GS regulation under the 

Safe Drinking Water Act to protect USDWs and not for the purpose of addressing 

verification requirements for carbon credits. Accordingly, we specifically 

recommend that these requirements be published for comment in conjunction with a 

NODA if one is published. 

ATTACHMENT A 

Requirements for Geologic Sequestration 

Oil and Gas Reservoirs 

§ 146.25 Geologic sequestration in oil or gas reservoirs for wells under 

§146.5(b)(5) 

Except as otherwise provided in this section, injection wells used for geologic 

sequestration and meeting the classification criteria of 40 C.F.R. §146.5(b)(5) 

shall be subject to the following requirements in lieu of the requirements of 40 

C.F.R. §146.22-24: 

(a) Minimum Criteria for Siting - The owner or operator must have demonstrated 

to the satisfaction of the Director that existing wells are, and new wells will 

be, sited in areas with a suitable geologic system. The geologic system must be 

comprised of: 

(1) An injection zone of sufficient areal extent, thickness, porosity, and 

permeability to receive the total anticipated volume of the carbon dioxide 

stream; 

(2) A confining zone(s) that is laterally continuous and free of known 

transmissive faults or fractures over an area sufficient to prevent the movement 

of fluids that endangers a USDW; 

(b) Area of Review and Corrective Action 

(1) The area of review is based on computational modeling using all available 

data including monitoring and operational data that account for the physical and 

chemical properties of all phases and volumes of the injected carbon dioxide 

stream. 
(2) The owner or operator must prepare, maintain, and comply with a plan to 

delineate the area of review for a proposed geologic sequestration project under 

this section, reevaluate the delineation, and perform corrective action that 

meets the requirements of this section in a manner and at a frequency acceptable 

to the Director. As a part of the permit application or revision, the owner or 

operator must submit an area of review and corrective action plan that includes 

the following information: 

(i) The method for delineating the area of review that meets the requirements of 

§146.25(b)(1) and (3), including the model to be used, assumptions that will be 

made, and the site characterization and other data including any existing 

monitoring data on which the model will be based; 

(ii) A description of: 

(A) How monitoring and operational data (e.g., injection rate and pressure) will 

be used to inform an area of review reevaluation; and 

(B) How corrective action will be conducted to meet the requirements of 

§146.25(b)(4), including what corrective action will be performed prior to 

injection and what, if any, portions of the area of review will have corrective 

action addressed on a phased basis and how the phasing will be determined; how 

corrective action will be adjusted if there are changes in the area of review; 

and how site access will be assured for future corrective action. 

(3) The owner or operator must perform the following actions to delineate the 

area of review, identify all wells that require corrective action, and perform 

corrective action on those wells: 

(i) Project, using computational modeling and available monitoring data, the 

projected lateral and vertical migration of the carbon dioxide plume and 

formation fluids in the subsurface from the commencement of carbon dioxide 

injection activities until the plume movement ceases or pressure differentials 

sufficient to cause the movement of injected fluids or formation fluids into a 

USDW are no longer present. The model must: 

(A) Be based on detailed geologic data collected to characterize the injection 

and confining zones, available monitoring data, and on anticipated operating 

data, including injection pressures, rates and total volumes over the duration 

of injection; 

(B) Take into account relevant geologic heterogeneities, and data quality, and 

their possible impact on model projections; and 

(C) Consider potential migration through faults, fractures, and artificial 

penetrations. 

(ii) Using methods approved by the Director, identify all known artificial 

penetrations into the confining zone, including active, inactive and abandoned 
wells and underground mines, in the area of review that may penetrate the 

confining zone. Provide a description of each well’s type, construction, date 

drilled, location, depth, record of plugging and/or completion, and any 

additional information the Director may require; and 

(iii) Determine which abandoned wells identified in §146.25(b)(3)(ii) have been 

plugged in a manner that prevents the movement of carbon dioxide or displaced 

formation fluids that may endanger USDWs; 

(iv) Determine which inactive wells identified in §146.25(b)(3)(ii) have been 

completed in a manner that prevents the movement of carbon dioxide or displaced 

formation fluids that may endanger USDWs. 

(4) The owner or operator must perform corrective action using materials 

suitable for use with the carbon dioxide stream on all wells identified in 

§146.25(b)(3)(ii) that are determined to need corrective action in accordance 

with 146.25(b)(2)(ii)(B). 

(5) When monitoring and operational conditions warrant, including in conjunction 

with reviews conducted pursuant to §146.25(h)(4), the owner or operator must: 

(i) Reevaluate the area of review in the same manner specified in §146.25(b)(3) 

(i); 

(ii) Identify all wells in the reevaluated area of review that require 

corrective action in the same manner specified in §146.25(b)(3)(ii). 

(iii) Perform corrective action on wells requiring corrective action in the 

reevaluated area of review in the same manner specified in §146.25(b)(2)(ii)(B) 

and (4); and 

(iv) Submit an amended area of review and corrective action plan or demonstrate 

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

the area of review and corrective action plan is needed. 

(6) The emergency and remedial response plan (as required by §146.25(l)) and a 

demonstration of financial responsibility (as required by §146.25(c)) must 

account for the entire area of review (as modified) regardless of whether or not 

corrective action in the area of review is phased. 

(c) Financial Assurance 

(1) The owner or operator must demonstrate the adequacy of existing financial 

responsibility or provide and maintain financial responsibility and resources 

for: corrective action (that meets the requirements of § 146.25 (b)), injection 

well plugging (that meets the requirements of § 146.25(j)), and post-injection 

site care and site closure (that meets the requirements of § 146.25 (k) and 

emergency and remedial response (that meets the requirements of § 146.25(l) in a 

manner prescribed by the Director until: 
(i) The Director receives well plugging report identified in §146.25(j)(4) or 

completion of the post-injection site care and site closure plan as appropriate; 

and 

(ii) The Director determines that the site has reached the end of the postinjection site care period. 

(2) The owner or operator must provide to the Director, at a frequency 

determined by the Director, but no more frequently than annually, written 

updates or adjustments to the cost estimate to account for any changes to the 

area of review and corrective action plan (§146. 25(b)(2)), the injection well 

plugging plan (§146. 25(j)(2)), and the post-injection site care and site 

closure plan (§146. 25(k)(1)). 

(3) The owner or operator must notify the Director of adverse financial 

conditions that may affect the ability to carry out injection well plugging and 

post-injection site care and site closure. 

(4) The owner or operator must provide an adjustment of the cost estimate to the 

Director if the Director has reason to believe that the most recent 

demonstration is no longer adequate to cover the cost of injection well plugging 

(as required by §146. 25(j)) and post-injection site care and site closure (as 

required by §146. 25(k)). 

(d) Well Construction Requirements 

(1) Applicability 

(i) Existing wells must meet the construction requirements of 40 C.F.R. §146.22. 

(ii) Newly-drilled wells in existing fields where carbon dioxide injection has 

occurred are subject to the construction requirements of 40 C.F.R. §146.22 if: 

(A) They meet the requirements for casing and cementing applicable to permitted 

Class II injection wells operated in that field in conjunction with the 

extraction of hydrocarbons; and 

(B) Well injection will not result in the movement of fluids into an underground 

source of drinking water so as to create a significant risk to the health of 

persons. 

(iii) Except as provided in paragraph (d)(1)(ii) of this section, newly-drilled 

wells shall be subject to the requirements of subsection (d)(2) of this section. 

(2) Construction Requirements for newly-drilled injection wells. 

(i) General. The owner or operator must ensure that newly-drilled injection 

wells are constructed and completed to: 

(A) Prevent the movement of fluids that endangers a USDW; 
(B) Permit the use of appropriate testing devices and workover tools; and 

(C) Permit continuous monitoring of the annulus space between the injection 

tubing and long string casing. 

(ii) Casing and cement or other materials used in the construction of each well 

to which this section is applicable must have sufficient structural strength and 

be designed for the life of the operating life of the well. All well materials 

must be compatible with fluids with which the materials may be expected to come 

into contact and meet or exceed test standards or practices developed for such 

materials by the American Petroleum Institute, ASTM International, or comparable 

standards acceptable to the Director. The casing and cementing program must be 

designed to prevent the movement of fluids that endangers USDWs. In order to 

allow the Director to determine and specify casing and cementing requirements, 

the owner or operator must provide the following information: 

(A) Depth to the injection zone; 

(B) Hole size; 

(C) Size and grade of all casing strings (wall thickness, external diameter, 

nominal weight, length, joint specification and construction material); 

(D) Predicted corrosive characteristic of the combined carbon dioxide stream and 

formation fluids; 

(E) Down-hole temperatures and pressures; 

(F) Lithology of injection and confining zones; 

(G) Type or grade of cement and additives; and 

(H) Quantity, chemical composition, and temperature of the carbon dioxide 

stream. 

(iii) Casing must extend through the base of the lowermost USDW above the 

injection zone and be cemented to the surface. Surface casing need not extend 

through the base of the lowermost USDW above the injection zone if a combination 

of cement around the surface casing and intermediate or long-string casing 

achieves continuous cement through the base of the lowermost USDW above the 

injection zone. 

(iv) At least one long string casing, using a sufficient number of centralizers, 

which at a minimum, would create a cement bond through the confining zone, and 

which must extend to the injection zone and must be isolated by placing cement 

and/or other isolation technologies as necessary to provide adequate isolation 

of the injection zone and provide for protection of USDWs. 

(v) Cement and cement additives must be suitable for use with the carbon dioxide 

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

integrity over the operating life the well. The integrity and location of the 

cement shall be verified using technology capable of evaluating cement quality 

and identifying the location of channels to ensure that USDWs are not 

endangered. 

(vi) Tubing and packer. 

(A) Owners and operators must inject fluids through tubing with a packer set at 
a depth opposite a cemented interval at the location approved by the Director. 

(B) In order for the Director to determine and specify requirements for tubing 

and packer, the owner or operator must submit the following information: 

(1) Depth of setting and the depth of the injection zone; 

(2) Composition of the carbon dioxide stream. 

(3) Maximum proposed Injection temperature and pressure; 

(4) Maximum proposed Annular pressure; 

(5) Maximum proposed Injection rate (intermittent or continuous) and volume of 

the carbon dioxide stream; 

(e) Logging, sampling, and testing prior to new well operation - The following 

requirements apply only to newly-drilled wells. 

(1) During the drilling and construction of an injection well, the owner or 

operator must run appropriate logs, surveys and tests to determine or verify the 

depth, thickness, porosity, permeability, and lithology of, and the salinity of 

any formation fluids in, all relevant geologic formations to evaluate 

conformance with applicable injection well construction requirements and to 

establish accurate baseline data against which future measurements may be 

compared. The owner or operator must submit to the Director a descriptive report 

prepared by a knowledgeable log analyst that includes an interpretation of the 

results of such logs and tests. The Director may require such logs and tests as 

may be needed after taking into account the availability in the area of the 

drilling site of data having similar quality and reliability as would be 

obtained with new logs and tests, the construction plan, and the need for 

additional information that may arise from time to time as the construction of 

the well progresses and these may include the following: 

(i) Deviation checks during drilling on all holes constructed by drilling a 

pilot hole that is enlarged by reaming or another method. Such checks must be at 

sufficiently frequent intervals to determine the location of the borehole and to 

assure that vertical avenues for fluid movement in the form of diverging holes 

are not created during drilling; 

(ii) Before and upon installation of the surface casing: 

(A) Resistivity, spontaneous potential, and caliper logs before the casing is 

installed; and 

(B) A cement evaluation log or logs after the casing is set and cemented. 

(iii) Before and upon installation of the long string casing: 

(A) Resistivity, spontaneous potential, porosity, caliper, gamma ray and any 

other logs the Director requires based on site specific conditions and riskbased factors for the given geology before the casing is installed; and 

(B) Cement evaluation log(s) and/or map(s) after the casing is set and cemented 
to evaluate cement quality with sufficient radial resolution to identify 

channels or missing cement that would prevent compliance with §146.25(d)(2). 

(iv) Test(s) designed to demonstrate the internal and external mechanical 

integrity of injection wells, which may include: 

(A) A pressure test with liquid or gas; 

(B) Diagnostic tools such as oxygen-activation logging; 

(C) A temperature or noise log; 

(D) A casing inspection log; and 

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

that are required of and/or approved of by the Director. 

(2) The owner or operator must submit to the Director a report describing whole 

cores or sidewall cores representative of the injection zone and confining 

system and formation fluid samples from the injection zone(s). The Director may 

accept data from cores and fluid samples from nearby wells if the owner or 

operator can demonstrate that such data are representative of conditions in the 

wellbore. 

(3) Prior to injection well operation, the owner or operator must record the 

formation temperature, formation fluid pH and conductivity, and reservoir 

pressure of the injection zone(s). 

(4) At any time prior to injection well operation, the owner or operator must 

determine fracture pressures of the injection and confining zones and conduct 

tests to verify hydrogeologic and geomechanical characteristics of the injection 

zone. 

(5) The owner or operator must provide the Director with the opportunity to 

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

submit a schedule of such activities to the Director upon spudding the well and 

submit any changes to the schedule 48 hours prior to the scheduled test. 

(f) Injection well operating requirements 

(1) The owner or operator must comply with a maximum injection pressure limit 

approved by the Director and specified in the permit. In approving a maximum 

injection pressure limit, the Director shall consider the results of well tests 

and, where appropriate, geomechanical or other studies that assess the risks of 

tensile failure and shear failure. The Director shall approve limits that, with 

a reasonable degree of certainty, will avoid initiation or propagation of 

fractures in the confining zone or cause otherwise non-transmissive faults 

transecting the confining zone to become transmissive. In no case may injection 

pressure cause movement of injection or formation fluids in a manner prohibited 

by 40 C.F.R. §144.12(a). 

(2) Injection of the CO2 stream into any annulus or between the outermost casing 

protecting USDWs and the well bore is prohibited. 
(3) For injection wells constructed with injection tubing and packer, the owner 

or operator must fill the annulus between the tubing and the long string casing 

with a corrosion inhibiting fluid approved by the Director and must maintain a 

positive pressure on the annulus. 

(4) The owner or operator must install and use continuous recording devices to 

monitor: the injection pressure and the rate, volume, and temperature of the 

carbon dioxide stream. For injection wells constructed with injection tubing and 

packer, the owner or operator must regularly monitor the pressure on the annulus 

between the tubing and the long string casing. The owner or operator must 

install, test and use alarms and automatic shut-off systems, designed to alert 

the operator and shut-in the well when operating parameters such as injection 

rate, injection pressure, or other parameters approved by the Director diverge 

beyond ranges and/or gradients specified in the permit. 

Notes: 

The duty to establish and maintain mechanical integrity is already imposed under 

40 C.F.R. §144.51(q)(1). 

Requirements for responding to a potential lack of mechanical integrity are 

imposed under 40 C.F.R. §144.51(q). 

Requirements for 24-hour reporting are imposed under 40 C.F.R. §144.51(l)(6). 

(5) Mechanical integrity 

(i) A well has mechanical integrity if: 

(A) There is no significant leak in the casing, tubing or packer; and 

(B) There is no significant fluid movement into a USDW through channels adjacent 

to the injection well bore. 

(ii) To evaluate the absence of significant leaks under this subsection, owners 

or operators must, following an initial annulus pressure test, continuously 

monitor and record at least daily injection pressure, rate, injected volumes, 

and - for wells constructed with an injection tube and packer - pressure on the 

annulus between tubing and long stem casing and annulus fluid volume as 

specified in §146.25(g)(2)(ii); 

(iii) At least once per year, the owner or operator must confirm the absence of 

significant fluid movement under paragraph (5)(i)(B) of this section using a 

method acceptable to the Director (e.g. including diagnostic surveys such as 

oxygen-activation logging or temperature or noise logs). 

(iv) The Director may require any other test to evaluate mechanical integrity 

under paragraph (i)(A) or (i)(B) of this section. Also, the Director may allow 

the use of a test to demonstrate mechanical integrity other than those listed 

above with the written approval of the Administrator. To obtain approval, the 

Director must submit a written request to the Administrator, which must set 
forth the proposed test and all technical data supporting its use. The 

Administrator must approve the request if it will reliably demonstrate the 

mechanical integrity of wells for which its use is proposed. Any alternate 

method approved by the Administrator will be published in the Federal Register 

and may be used in all States in accordance with applicable State law unless its 

use is restricted at the time of approval by the Administrator. 

(v) In conducting and evaluating the tests enumerated in this section or others 

to be allowed by the Director, the owner or operator and the Director must apply 

methods and standards generally accepted in the industry. When the owner or 

operator reports the results of mechanical integrity tests to the Director, 

he/she shall include a description of the test(s) and the method(s) used. In 

making his/her evaluation, the Director must review monitoring and other test 

data submitted since the previous evaluation. 

(vi) The Director may require additional or alternative tests if the results 

presented by the owner or operator under paragraph (d) of this section are not 

satisfactory to the Director to demonstrate that there is no significant leak in 

the casing, tubing or packer or significant movement of fluid into or between 

USDWs resulting from the injection activity as stated in paragraphs (i)(A) and 

(i)(B) of this section. 

(g) Testing and Monitoring 

(1) Based on a site-specific assessment of the potential for fluid movement from 

the injection well or injection zone, and on the potential value of monitoring 

wells to detect such movement, the owner or operator of a well must prepare, 

maintain, and comply with a testing and monitoring plan. The testing and 

monitoring plan must be submitted with the permit application for Director 

approval, and must include a description of how the owner or operator will meet 

the requirements of this section. 

(2) The testing and monitoring plan must, at a minimum, include: 

(i) analysis of the carbon dioxide stream with sufficient frequency to yield 

data representative of its chemical and physical characteristics; 

(ii) Installation and use, except during well workovers as defined in section 

146.88(d), of continuous monitoring devices (including digital devices capturing 

periodic data) to monitor injection pressure, rate and volume; and, for wells 

constructed with injection tubing and packer, to record at least daily the 

pressure on the annulus between the tubing and the long strong casing; 

(iii) demonstration of external mechanical integrity pursuant to §146.25(f)(5) 

until the well is plugged; 

(iv) monitoring of the pressure buildup in the injection zone annually, 

including at a minimum, a shut down of the well for a time sufficient to conduct 

a valid observation of the pressure fall-off curve at least once every five 

years; and 
(v) a quality assurance plan. 

(3) Where appropriate, the testing and monitoring plan shall also include: 

(i) Continuous monitoring for pressure changes in an appropriately porous and 

permeable formation overlying the confining zone. When a well is installed to 

enable such monitoring, the owner or operator shall, on a specified frequency or 

at specified times, sample the formation and analyze for constituents specified 

in the plan; 

(ii) The use of indirect, geophysical techniques to determine the position of 

the CO2 stream front, the water quality in a designated formation, or to provide 

other site specific data; 

(iii) Periodic monitoring of water quality in an appropriately porous and 

permeable formation overlying the injection zone; 

(iv) Periodic monitoring of water quality in one or more USDWs; 

(v) Corrosion monitoring of the well materials for loss of mass, thickness, 

cracking, pitting and other signs of corrosion performed and recorded at least 

quarterly which may be modified to be less frequent as approved by the Director 

based on construction materials, operating conditions, and monitoring history to 

ensure that the well components meet minimum standards for material strength and 

performance by: 

(A) Analyzing coupons of the well construction materials placed in contact with 

the carbon dioxide stream; or 

(B) Routing the carbon dioxide stream through a loop constructed with the 

material used in the well and inspecting the materials in the loop; or 

(C) Using an alternative method, materials, or time period approved by the 

Director; 

(vi) Any additional monitoring, as required by the Director, based on sitespecific conditions and risk-based factors, necessary to support, upgrade, and 

improve computational modeling of the area of review evaluation required under § 

146.84(b); and 

(vii) Any additional testing and monitoring necessary to determine whether fluid 

movement is occurring that would endanger a USDW. 

(h) Reporting and Certification Requirements 

The owner or operator must, at a minimum, provide the following reports to the 

Director, for each permitted well: 

(1) Semi-annual or less frequently as determined by the Director reports 

containing: 
(i) Any significant changes to the physical, chemical and other relevant 

characteristics of the carbon dioxide stream from the proposed operating data; 

(ii) Monthly average, maximum and minimum values for injection pressure, flow 

rate and volume, and annular pressure; 

(iii) A description of any event that significantly exceeds operating parameters 

for annulus pressure or injection pressure as specified in the permit; 

(iv) A description of any event which triggers a shutdown device required 

pursuant to §146.25(f)(4) and the response taken; 

(v) The monthly volume of the carbon dioxide stream injected over the reporting 

period and project cumulatively; 

(vi) Monthly annulus fluid volume added; and 

(vii) The results of monitoring prescribed under §146.25(g). 

(2) Report, within 30 days the results of: 

(i) Periodic tests of mechanical integrity; 

(ii) Any other test of the injection well conducted by the permittee if required 

by the Director; and 

(iii) Any well workover. 

(3) Owners or operators must submit reports in an electronic format acceptable 

to the Director. At the discretion of the Director, other formats may be 

accepted. 

(4) Owners or operators must submit an annual certification, signed by the 

appropriate company official, that the company has: 

(i) reviewed the area of review and all of the required plans; 

(ii) reviewed all monitoring and operational data since the previous 

certification that are relevant to a decision on whether to update the area of 

review and each plan; 

(iii) determined with regard to the area of review and each plan whether an 

update was warranted; and 

(iv) completed an update pursuant to section 146.84(f) for the area of review if 

warranted by material change, 

(v) completed an update and attached a summary of the modifications for each of 

the plans for which an update was warranted by material change. 

(5) The Director may require submission of copies of any updated plans and/or 

additional information regarding the reasons why updates of particular plans 

have or have not been prepared. 

(6) The Director may require reevaluation of the area of review pursuant to 

section 146.84(f) or the revision of any required plan whenever the Director 

determines on the basis of information available to him that an update is 

necessary to comply with the requirements of this Subpart. 

(i) Required permit information 

This section sets forth the information which the owner or operator must submit 
to the Director in order to be permitted. The application for a permit for 

construction and operation of an injection well must include the following: 

(1) Information required in 40 CFR 144.31(e)(1) through (6); 

(2) A surface map showing the proposed locations for the injection well(s) for 

which a permit is sought and the applicable area of review. Within the area of 

review, the map must show the number, or name and location of all known 

injection wells, producing wells, abandoned wells, plugged wells or dry holes, 

deep stratigraphic boreholes, State or EPA approved subsurface cleanup sites, 

surface bodies of water, springs, mines (surface and subsurface), quarries, 

water wells and other pertinent surface features including structures intended 

for human occupancy and roads. Only information of public record is required to 

be included on this map; 

(3) A map delineating the area of review based upon modeling, using all 

available data including data available from any logging and testing of wells 

within the area of review. 

(4) Sufficient information on the geologic structure and reservoir properties of 

the proposed storage site and overlying formations, which may include: 

(i) Isopach maps of the proposed injection and confining zone(s), a structural 

contour map aligned with the top of the proposed injection zone, and at least 

two geologic cross sections of the area of review reasonably perpendicular to 

each other showing the geologic formations from the surface to total depth of 

the well. 

(ii) Location, orientation, and properties of known or suspected subsurface 

faults that may transect the confining zone(s) in the area of review and a 

determination that they would not interfere with containment; 

(iii) Information on seismic history that have affected the proposed area of 

review including knowledge of previous seismic events and history of these 

events, including the presence and depth of seismic sources and a determination 

that the seismicity would not compromise containment; 

(iv) Data sufficient to demonstrate the effectiveness of the injection and 

confining zone(s), including data on the depth, areal extent, thickness, 

mineralogy, porosity, vertical permeability reservoir pressure and of the 

injection and confining zone(s) within the area of review; including geologic 

changes based on field data which may include geologic cores, outcrop data, 

seismic surveys, well logs, capillary pressure tests and names and lithologic 

descriptions; 

(v) Geomechanical information on the confining zone(s) within the area of 

review; and 

(vi) Geologic and topographic maps and cross sections illustrating geology, 

hydrogeology, and the geologic structure of the area of review. 
(5) A compilation of all artificial penetrations within the area of review which 

penetrate the injection or confining zone(s). Such data must include a 

description of each well’s type, construction, date drilled, location, depth, 

record of plugging and/ or completion, and any additional information the 

Director may require; 

(6) Maps and stratigraphic cross sections indicating the general vertical and 

lateral limits of all USDWs, the location of water wells and perennial springs 

within the area of review, their positions relative to the injection zone(s) and 

the direction of water movement, where known; 

(7) A compilation of available baseline geochemical data on the proposed 

injection zone and nearest adjacent porous and permeable formation to the 

confining zone, existing utilized water supply aquifers and any other USDWs 

designated by the Director. 

(8) Proposed operating data: 

(i) Average and maximum daily injection rate and volume of the carbon dioxide 

stream; 

(ii) Average and maximum surface injection pressure; 

(iii) The source of the carbon dioxide stream; and 

(iv) An analysis of the chemical and physical characteristics of the carbon 

dioxide stream; 

(9) The compatibility of the carbon dioxide stream with fluids in the injection 

zone and minerals in both the injection and the confining zone(s), based on the 

results of the formation testing program or other data, and with the materials 

used to construct the well; 

(10) Proposed formation testing program to obtain an analysis of the chemical 

and physical characteristics of the injection zone and confining zone; 

(11) Proposed stimulation program and a determination that stimulation will not 

compromise containment; 

(12) The results of the formation testing program as required in paragraph (j) 

of this section; 

(13) Proposed procedure to outline steps necessary to conduct injection 

operation; 

(14) A wellbore schematic of the subsurface construction details and surface 

wellhead construction; 

(15) Injection well construction procedures that meet applicable requirements; 

(16) Proposed corrective action plan for artificial penetrations within the area 

of review, if necessary; 
(17) All available logging and testing program data on the well required by 

§146.25(e)(1); 

(18) The proposed demonstration method for mechanical integrity pursuant to 

§146.25(j)(5); 

(19) A demonstration, satisfactory to the Director, that the applicant has met 

the financial responsibility requirements under §146.25(c); 

(20) Proposed testing and monitoring plan required by §146.25(g); 

(21) Proposed injection and monitoring well(s) plugging plan required by 

§146.25(j)(2); 

(22) Proposed post-injection site care and site closure plan required by 

§146.25(k); 

(23) Proposed emergency and remedial response plan required by § 146.25(l); and 

(24) Any other information requested by the Director. 

(j) Injection well plugging 

(1) Prior to the well plugging, the owner or operator must flush each injection 

well with a buffer fluid, determine bottomhole reservoir pressure, and perform a 

final external mechanical integrity test. 

(2) Well Plugging Plan. The owner or operator of a well must prepare, maintain, 

and comply with a plan that is acceptable to the Director. The requirement to 

maintain and implement an approved plan is directly enforceable regardless of 

whether the requirement is a condition of the permit. The well plugging plan 

must be submitted as part of the permit application and must include the 

following information: 

(i) Appropriate test or measure to determine bottomhole reservoir pressure; 

(ii) Appropriate testing methods to ensure final external mechanical integrity 

as specified in §146.25(f)(5); 

(iii) The type and number of plugs to be used; 

(iv) The placement of each plug including the elevation of the top and bottom of 

each plug; 

(v) The type and grade and quantity of material to be used in plugging. The 

material must be suitable for use with the carbon dioxide stream, reservoir and 

fluid conditions; and 

(vi) The method of placement of the plugs. 

(3) Notice of intent to plug. The owner or operator must notify the Director at 

least 60 days before plugging of a well. At this time, if any changes have been 

made to the original well plugging plan, the owner or operator must also provide 

the revised well plugging plan. At the discretion of the Director, a shorter 
notice period may be allowed. 

(4) Plugging report. Within 60 days after plugging the owner or operator must 

submit a plugging report to the Director. The report must be certified as 

accurate by the owner or operator and by the person who performed the plugging 

operation (if other than the owner or operator.) 

(k) Post-injection site care and site closure 

(1) The owner or operator of a well must prepare, maintain, and comply with a 

plan for post-injection site care and site closure that meets the requirements 

of paragraph (1)(ii) of this section and is acceptable to the Director. 

(i) 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. 

(ii) The post-injection site care and site closure plan must include the 

following information: 

(A) The pressure differential between pre-injection and projected post-injection 

pressures in the injection zone; 

(B) The projected position of the carbon dioxide plume and associated pressure 

front at site closure as demonstrated in the area of review evaluation required 

under §146.25(b)(1), (3) and (5); 

(C) A description of post-injection monitoring location, methods, and proposed 

frequency; and 

(D) A proposed schedule for submitting post-injection site care monitoring 

results to the Director. 

(iii) Upon cessation of injection, owners or operators of 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. 

(iv) 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 

(2) The owner or operator shall monitor the site following the cessation of 

injection. 

(i) The owner or operator shall continue to conduct monitoring as specified in 

the Director-approved post-injection site care and site closure plan, pursuant 

to the performance based criteria described in §146.25(k)(2)(iii). 

(ii) The owner or operator can request and demonstrate to the satisfaction of 

the Director that the post-injection site care and site closure plan should be 

revised to reduce the frequency of monitoring. 
(iii) Prior to authorization for site closure, the owner or operator must 

demonstrate to the Director, based on monitoring, other site-specific data, and 

modeling that is reasonably consistent with site performance that no additional 

monitoring is needed to assure that the geologic sequestration project does not 

pose an endangerment to USDWs. The owner or operator must demonstrate, based on 

the current understanding of the site, including monitoring data and/or 

modeling, all of the following: (A) the estimated magnitude and extent of the 

project footprint (CO2 plume and the area of elevated pressure) ; (B) the 

estimated location of the detectable CO2 plume ; (C) that there is no 

significant leakage of either CO2 or displaced formation fluids that is 

endangering USDWs; (D) that the injected or displaced fluids are not expected to 

migrate in the future in a manner that encounters a potential leakage pathway 

into a USDW; (E) that the injection wells at the site completed into or through 

the injection zone or confining zone are plugged and abandoned in accordance 

with these requirements; and (F) any remaining project monitoring wells at the 

site are being managed by a person and in a manner acceptable to the Director. 

(3) 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. 

(4) After the Director has authorized site closure, 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. 

(5) Once the Director has authorized site closure, the owner or operator must 

submit a site closure report within 90 days after completion of all closure 

operations. The report must include: 

(i) Documentation of appropriate injection and monitoring well plugging as 

specified in §146.25(j) and paragraph (4) 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(s) 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; 

(ii) 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 

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

dioxide stream. 

(6) Each owner or operator of a injection well must provide notification to the 
designated state authority of the following information: 

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

(ii) 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 

(iii) The volume of fluid injected, the injection zone or zones into which it 

was injected, and the period over which injection occurred. 

(7) 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. 

(l) Emergency and Remedial Response Plan 

(1) As part of a permit application or request for revision to operate under 

this section, the owner or operator must provide the Director with an emergency, 

risk-based remedial response plan that describes actions to be taken to address 

movement of the injection or formation fluids that may cause an endangerment to 

a USDW during construction, operation, closure and post-closure periods. 

(2) If the owner or operator obtains evidence that the injected carbon dioxide 

stream, displaced formation fluids or and associated pressure front endangers a 

USDW, the owner or operator must: 

(i) Cease injection in a prudent manner considering circumstances. 

(ii) Take all steps reasonably necessary to identify and characterize the 

endangerment posed; 

(iii) Notify the Director or the designated representative within 24 hours of 

becoming aware of the endangerment; and 

(iv) Implement the emergency and remedial response plan approved by the Director 

and keep the Director apprized of the implementation. 

(3) The Director may allow the operator to resume injection prior to remediation 

if the owner or operator demonstrates that the injection operation will not 

endanger USDWs. 

(4) The owner or operator must notify the Director and obtain his approval prior 

to conducting any well workover or other remediation measures not listed in the 

emergency and remedial response plan. 

(5) If an owner or operator obtains evidence that a pressure front associated 

with one geologic sequestration project intersects or will intersect the area of 
review associated with another project, the owner or operator obtaining such 

evidence must notify the Director. If the Director determines that the pressure 

front associated with one project will interfere with the ability of another 

project to comply with the terms of its permit(s), the Director may require the 

owner or operator of the potentially interfering project to modify operations as 

necessary to avoid such interference. Such modification may include mutually 

agreed modifications in operations to both projects or other actions if the 

respective owners and operators agree to requirements to implement modifications 

or other actions approved by the Director that will mitigate the interference." 

Note: Requirements for responding to a potential lack of mechanical integrity 

are imposed under 40 C.F.R. §144.51(q). Requirements for 24-hour reporting are 

imposed under 40 C.F.R. §144.51(l)(6). 

Response: As described above, EPA agrees that injection of CO2 for the primary purpose of

enhancing oil and gas recovery should remain under the Class II Program, but that there are

significant differences between how EOR and GS projects are operated for purposes of protecting

USDWs from endangerment. EPA does not believe that GS in oil and gas formations should be

regulated separately from GS in other geologic formations or that the creation of a Class VII well

category for GS is necessary. EPA has taken a regulatory approach which promotes USDW

protection, incorporates flexibility or the discretion of the permitting authority when appropriate,

seeks to limit burden on owners or operators and permitting agencies, and provides a foundation for

national consistency in permitting of GS projects. For example, under the final rule, many of the

permit requirements must be established through site-specific plans (e.g., AOR and corrective action

plan, testing and monitoring plan, etc.) developed by the owner or operator and approved by the

Director. Consequently EPA expects that owners or operators will consult with the Director as they

develop, implement, and update these plans. Additionally, the Director has the discretion to approve

alternatives to the requirements in some cases. For example, the Director may in certain situations

modify the length of the post-injection site care period under §146.93, allow the use of alternate

methods for mechanical integrity testing under §146.89, or grant waivers from the requirement to

inject below the lowermost USDW under §146.95.

The Agency believes that the nature and risks of CO2 injection for the primary purpose of long term

storage poses different risks than injection for the primary purpose of EOR, and therefore has

developed new Class VI regulations to address these unique risks. For example, the volume of CO2

anticipated to be injected for long term storage is significantly greater than for EOR operations.

Reservoir pressure conditions will also be different, with Class VI injection operations involving

large volumes of CO2 and likely having higher pressures within their storage formations than Class

II EOR projects, which may lead to fluid movement that endangers a USDW.

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment EPA has made many revisions to the GS Rule. For more information, please

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

Commenter Name: George Peridas Letter ID: 0291

Commenter Organization: Natural Resources Defense Council Comment ID: 25286

Other EPA Comment Codes and Descriptions: 2146 1.6.2.2 Comments opposing injection into

depleted reservoirs 

Comment: Second, we highlight that the final rule needs to cater for GS in hydrocarbon 
reservoirs as well, and not just saline formations as proposed. Hydrocarbon 

reservoirs are likely to be among the first ones to be used for GS, and they 

need to be regulated appropriately. We do not believe that automatic delegation 

to Class II "as long as any production is occurring" is suitable. Under the 

economic driver of carbon constraints, additional risks might be posed in these 

reservoirs if operators inject larger volumes or at higher rates and pressures 

than they have been doing to date under Class II. Moreover, site 

characterization, operation, monitoring and closure requirements over and above 

the existing Class II will be needed to certify and assure "geologic 

sequestration" of injected carbon dioxide in hydrocarbon reservoirs. 

Response: EPA clarifies that the final rule is designed to address all types of formations in which

GS could take place. All applicants for GS wells must demonstrate that the proposed injection zone

is suitable for receiving carbon dioxide and that the confining zone can contain the injected carbon

dioxide and any displaced formation fluids. 

EPA believes that large-scale GS presents unique technical challenges, 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. For

this reason, EPA has finalized the tailored requirements in the GS rule.

EPA further clarifies that the GS rule is not intended to promote a preference for GS in any

particular formation type, to address use of resources, or to reduce costs associated with GS into

various formations. The focus of the GS rule is to ensure that, where GS is deployed, it is conducted

in a manner that protects USDWs from endangerment.

EPA clarifies that owners and operators of traditional EOR projects are subject to limits on injection

established under their Class II permits. If they exceed those limits, they will be considered to be in

violation of their Class II permit. EPA further clarifies that wells injecting into oil and gas formations

for the primary purpose of long-term containment of carbon dioxide are subject to the site

characterization, operation, monitoring, and closure requirements for Class VI wells in Subpart H of

40 CFR 146. For more information, please see the discussion on transition of Class II wells in the

preamble to the final GS rule.

Commenter Name: George Peridas Letter ID: 0291

Commenter Organization: Natural Resources Defense Council Comment ID: 25288

Other EPA Comment Codes and Descriptions: 2146 1.6.2.2 Comments opposing injection into

depleted reservoirs 

Comment: • EPA must promulgate appropriate requirements for GS in hydrocarbon reservoirs 

in the current rulemaking. The mere continuation of hydrocarbon production in 

those fields is not a valid criterion for well classification; 

Response: As described above, the final GS rule does not preclude injection into any non-USDW

formation type, including hydrocarbon reservoirs, provided owners or operators can demonstrate that

GS can be performed in a manner that protects USDWs from endangerment. 

EPA agrees that tailored requirements for Class VI wells are necessary to address the unique nature

of injecting large volumes of CO2 and to ensure that USDWs are protected from endangerment. The

GS rule contains tailored requirements for the permitting, geologic site characterization, AoR and
corrective action, well construction, operation, mechanical integrity testing, monitoring, well

plugging, post-injection site care, and site closure of GS wells that directly address issues unique to

the nature of large-scale CO2 injection for GS.

Commenter Name: George Peridas Letter ID: 0291

Commenter Organization: Natural Resources Defense Council Comment ID: 25290

Comment: • Class II as it exists today should continue to apply to operations that inject 

carbon dioxide for the sole purpose of enhanced oil recovery as opposed to GS; 

• Class II as it exists today should not be associated with the definition or 

the purpose of GS; 

• A separate injection class or subclass with appropriate site characterization, 

operation, monitoring and closure provisions should govern all injection in 

hydrocarbon reservoirs for the (sole or concurrent) purpose of GS as defined 

above (which includes earning carbon credits) and injection that exceeds 

business-as-usual Class II volume, pressure or other key thresholds that result 

in greater risk; 

• The primacy delegation criteria for this class or subclass should be subject 

to the primacy delegation requirements that apply to Class VI as proposed, and 

not to the more general showing used for Class II; and 

• In order to be able to utilize existing wells in hydrocarbon reservoirs for 

GS, this class or subclass could allow for the transition of existing Class II 

wells into the class or subclass, provided that appropriate construction and 

mechanical integrity parameters are met, and provided that those wells begin 

compliance with the added site characterization, operation, monitoring, closure 

and other requirements in the new class or subclass. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. The Agency also believes that the nature and

risks of CO2 injection for the primary purpose of long term storage poses different risks than

injection for the primary purpose of EOR, and therefore has developed new Class VI regulations to

address these unique risks. For example, the volume of CO2 anticipated to be injected for long term

storage is significantly greater than for EOR operations. Reservoir pressure conditions will also be

different, with Class VI injection operations involving large volumes of CO2 and likely having

higher pressures within their storage formations than Class II EOR projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary

purpose of long term storage obtain a Class VI permit with some special consideration for the fact

that they are transitioning from a well not originally designed to meet Class VI requirements. The

Director has the authority to determine at what point a Class VI permit is required for those projects

that are transitioning from the primary purpose of EOR to long term storage of CO2. The final

regulation provides a set of technical factors for the Director to evaluate in making this

determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs

when there is an increased risk to USDWs as compared to traditional Class II operations while

allowing for site-specific flexibility. 
EPA anticipates that there will be GS/ER projects that were formerly classified as Class II that will

seek to be permitted as Class VI injection wells. EPA is allowing the construction of these wells to

be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director that

the wells were engineered and constructed to meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA believes that

allowing for grandfathering of select construction requirements, if approved by the Director, will

ease the transition to Class VI from an existing ER project while protecting 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 longterm 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.

Commenter Name: A. Scott Anderson Letter ID: 0293

Commenter Organization: Environmental Defense Fund Comment ID: 25280

Comment: (3). EDF believes that the Agency should take a different approach to regulating 

sequestration in the oilfield context than the approach embodied in the proposed 

rule. As proposed, the rule would allow some projects (i.e., projects in 

oilfield that produce incidental amounts of oil in conjunction with CO2 storage) 

to be regulated less stringently than is needed. Small amounts of oil production 

should be expected where CO2 is stored in "depleted" oilfields. Moreover, it 

should also be expected that reservoir pressures in such projects will 

materially exceed the pressures generally encountered in business-as-usual 

enhanced oil recovery projects. We believe that the risk profile presented by 

such projects should be addressed head-on - we do not believe the problem can be 

fixed simply by providing that all projects that produce any oil shall be 

regulated under existing Class II regulations or the Class VI will apply to 

projects that are "exclusively" or "primarily" or "specifically" for the purpose 

of sequestration. Instead, we believe that EPA should recognize, for Safe 

Drinking Water Act purposes, that three types of CO2 injection/storage 

activities present three different risk profiles and that therefore they ought 

to be regulated in three different ways. The three project types as we see it 

are: (a) injection/storage that takes place in conjunction with traditional 

Class II enhanced oil recovery operations; (b) CO2 storage in oilfields where in 

all probability there will continue to be some oil production but where the goal 

will be to pressure up the reservoir as high as possible in order to store as 

much CO2 as possible; and (c) CO2 storage in brine formations. While the 

December 23 Multi-Stakeholder Group letter does not suggest in detail how the 

regulation of sequestration in highly pressured oilfields might differ from both 

the existing Class II regulations and from the Class VI regulations as proposed, 

the December 23 submission does provide a suggested "bright line" that can be 

used to distinguish between the two types of oilfield activity. It is important, 

in our judgment, that the Agency consider modifying the proposed rule so that 
UIC regulation will be tailored to each of the three contexts outlined above. It 

will be important to solicit another round of public comment on this idea before 

adopting final regulations - something we hope can be done in conjunction with a 

NODA process. 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA clarifies that owners and operators of

traditional EOR projects are subject to limits on injection, including pressure limits, established

under their Class II permits. If they exceed those limits, they will be considered to be in violation of

the Class II UIC regulations. The Agency also agrees that the nature and risks of CO2 injection for

the primary purpose of long term storage poses different risks than injection for the primary purpose

of ER, and therefore has developed new Class VI regulations to address these unique risks. For

example, the volume of CO2 anticipated to be injected for long term storage is significantly greater

than for ER operations. Reservoir pressure conditions will also be different, with Class VI injection

operations involving large volumes of CO2 and likely having higher pressures within their storage

formations than Class II ER projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary

purpose of long term storage obtain a Class VI permit with some special consideration for the fact

that they are transitioning from a well not originally designed to meet Class VI requirements. The

Director has the authority to determine at what point a Class VI permit is required for those projects

that are transitioning from the primary purpose of EOR to long term storage of CO2. The final

regulation provides a set of technical factors for the Director to evaluate in making this

determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs

when there is an increased risk to USDWs as compared to traditional Class II operations while

allowing for site-specific flexibility. 

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 longterm 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.

EPA agrees that tailored requirements for Class VI wells are necessary to address the unique nature

of injecting large volumes of CO2 and to ensure that USDWs are protected from endangerment. The

GS rule contains tailored requirements for the permitting, geologic site characterization, AoR and

corrective action, well construction, operation, mechanical integrity testing, monitoring, well

plugging, post-injection site care, and site closure of GS wells that directly address issues unique to

the nature of large-scale CO2 injection for GS.

Commenter Name: Scott Anderson Letter ID: 0295

Commenter Organization: Environmental Defense Fund Comment ID: 26140

Other EPA Comment Codes and Descriptions: 2140 1.6.2 Depleted oil and gas reservoirs 

Comment: Second, EPA has so far failed to address another urgent need: regulating 

geologic sequestration in hydrocarbon (oil & gas) reservoirs. Instead, the 
proposed UIC rule concentrates on saline formations and addresses hydrocarbon 

reservoirs only in the event that production has entirely ceased. An oilfield, 

however, can continue producing small volumes in perpetuity, making cessation of 

production a meaningless concept as a threshold to entry into the regulatory 

scheme for CCGS. We consider this to be a serious shortcoming of the rule as 

currently proposed. Enhanced Oil Recovery (EOR) is a practice that has been 

taking place for several decades in the U.S., and is likely to play a pivotal 

part in the early years of geologic sequestration deployment. Reservoirs where 

EOR is occurring, or can occur, are generally better characterized than their 

saline counterparts, often have some of the needed infrastructure in place, and 

offer an additional economic incentive for the operation as a result of oil 

production revenues. Many regions in the U.S. possess significant EOR potential 

that remains untapped due the scarcity of acceptably priced CO2. Under climate 

legislation, or a CAA regulatory regime, this situation will change as large 

point sources capture their emissions. We therefore expect EOR to be utilized 

early during geologic sequestration deployment, for economic and practical 

reasons. Accordingly, EPA should prioritize development of airside regulations, 

including monitoring and verification protocols for situations where operators 

desire to simultaneously pursue EOR and geologic sequestration. Airside 

regulations should also be developed for sequestration taking place in oilfields 

where only minor amounts of oil production occur and the operation can no longer 

be considered EOR. 

Response: EPA acknowledges that GS falls within the broader context of CCS and the need for

regulatory clarity to ensure that USDWs are protected from endangerment. In developing the final

GS rule, the Office of Water coordinated with other Agency program offices and across federal

agencies (e.g., with the Department of Energy; United States Geological Survey; Bureau of Ocean

Energy Management, Regulation, and Enforcement, formerly the Minerals Management Service;

Bureau of Land Management). The Agency continues to evaluate areas of potential applicability of

other Federal environmental statutes including, but not limited to: the Clean Air Act; the Resource

Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, and

Liability Act; and the Marine Protection, Research and Sanctuaries Act to various aspects of GS and

CCS. The Agency will continue to coordinate on GS and CCS related issues to minimize redundancy

and maximize efficiencies for owners or operators. For additional information, please see the

discussion entitled "How Does This Rulemaking Relate to Other Federal Authorities and GS and

CCS Activities?" in the preamble to the final GS rule.

EPA notes that comments related to the development of “air side” regulations for EOR are outside

the scope of the GS rulemaking. However, in a separate rulemaking under authority of the Clean Air

Act, EPA is amending the Greenhouse Gas (GHG) Reporting Program at 40 CFR Part 98 to add

reporting requirements for facilities that conduct GS (subpart RR) and all other facilities that inject

CO2 underground (subpart UU).

In response to comments on depleted oil and gas reservoirs, EPA believes that injection of CO2 for

the primary purpose of enhancing oil and gas recovery should remain under the Class II Program,

and that the nature and risks of CO2 injection for the primary purpose of long term storage poses

different risks than injection for the primary purpose of ER. EPA therefore has developed new Class

VI regulations to address these unique risks. For more information, please see the discussion on

transition of Class II wells in the preamble to the final GS rule.
Commenter Name: Scott Anderson Letter ID: 0295

Commenter Organization: Environmental Defense Fund Comment ID: 26141

Comment: As EPA correctly recognizes in the preamble to the proposed Greenhouse Gas 

Reporting Rule, EOR business as usual and geologic sequestration are not the 

same. The former injects CO2 for the purposes of maximizing oil production, 

whereas the latter seeks to sequester the CO2 permanently in the subsurface. 

While EOR operations are quite likely to result in sequestration, operators now 

have no regulatory means to verify, measure, and certify its permanence. This 

shortcoming increasingly is being brought to our attention by EOR operators who 

have no recognized way of assuring owners of large CO2 point sources that 

injection operations result in permanent sequestration. These power plant or 

industrial facility owners already have two reasons to seek a certification of 

EOR as geologic sequestration: the carbon dioxide sequestration tax credit under 

Section 45Q of the tax code and the Department of Energy’s (DOE) Federal Loan 

Guarantee Program. Neither Treasury nor DOE currently has any environmental 

regulatory basis on which to rest a judgment about the degree of CO2 

sequestration provided by EOR operations. 

A third reason to develop standards is likely to be added to the list soon if 

Congress passes climate legislation. EPA’s current position that, as long as any 

amount of oil is produced, all oilfield sequestration operations can only be 

regulated under UIC Class II requirements, is damaging not only to the entities 

seeking to sequester the CO2 but to the Administration’s stated objectives on 

climate change. [FN 4] 

FN 4. We do not seek to change the rules for business-as-usual EOR operations 

where there is no objective to sequester CO2. 

Response: As described above, EPA clarifies that the Class VI GS rule is designed to ensure the

protection of USDWs from endangerment. Carbon crediting and green house gas accounting are

outside the scope of the GS rulemaking and outside of EPA’s authority under the SDWA. 

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: Scott Anderson Letter ID: 0295

Commenter Organization: Environmental Defense Fund Comment ID: 26143

Comment: • Create a regulatory framework for geologic sequestration, governing not only 
geologic sequestration in saline reservoirs, but also in oil & gas reservoirs. 

This framework should allow for hydrocarbon production as well as certification 

of secure sequestration. It should recognize the difference between 

sequestration that occurs in conjunction with traditional EOR operations and 

sequestration that may take place in hydrocarbon reservoirs in circumstances 

where production will tend to be low and storage pressures will tend to be high. 

Operators who do not wish to perform geologic sequestration can and should 

continue to be regulated under UIC Class II. 

Response: As described above, EPA agrees that injection of CO2 for the primary purpose of

enhancing oil and gas recovery should remain under the Class II Program, and that the nature and

risks of CO2 injection for the primary purpose of long term storage poses different risks than

injection for the primary purpose of ER. EPA therefore has developed new Class VI regulations to

address these unique risks. For more information, please see the discussion on transition of Class II

wells in the preamble to the final GS rule.

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.

Commenter Name: A. Scott Anderson Letter ID: 0296

Commenter Organization: Environmental Defense Fund Comment ID: 29476

Comment: On March 17,2009, Environmental Defense Fund (EDF) and Clean Air Task Force 

(CATF) wrote separate letters to you reaffirming the importance of suggestions 

we submitted on December 23, 2008 as part of the group generally known as the 

Multi-Stakeholder Group (MSG). We hoped that you would distribute copies of our 

March 17 letters to the EPA workgroup convened for this docket if you thought 

that distributing the letters would be appropriate. 

One of the subjects discussed in both the December 23 MSG letter and the March 

17 EDF and CATF letters is the importance, for Safe Drinking Water Act purposes, 

of: (1) drawing a "bright line" between two different types of CO2 injection 

projects in oil and gas fields; and (2) more clearly distinguishing injection 

projects in oil and gas fields from injection projects in brine formations. As 

explained in the letters, we believe there are three different types of CO2 

injection activity that present three different risk profiles and ought to be 

regulated in three different ways. We asked that the Agency solicit public 

comment on this subject as part of a NODA process. 

While the December 23 and March 17 letters discussed in a general way this 

three-fold approach to managing the risks of CO2 injection, and while the 

December 23 letter suggested "bright line" language we believe should be used to 
distinguish between the two types of injection projects in oil and gas fields, 

none of these letters set forth language that might be used to regulate the type 

of oilfield project that poses higher risk to the environment. We are aware that 

other MSG participants are forwarding to you today language that might be used 

for this purpose in Class II or in a new Class VII. We expect to support 

portions of this language and recommend changes in other portions. In order to 

move the process forward, however, we urge you to publish the language for 

public comment as part of the contemplated NODA. EDF and CATF will continue to 

work with other MSG participants on the issue and look forward to the 

opportunity to make detailed comments on this subject in the future. 

Response: EPA clarifies that the GS rule does not change the requirements or address Class II EOR

operations. EPA believes that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. EPA believes that the nature and risks of CO2

injection for the primary purpose of long term storage poses different risks than injection for the

primary purpose of EOR, and therefore has developed new Class VI regulations to address these

unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is

significantly greater than for ER operations. Reservoir pressure conditions will also be different, with

Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II EOR projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary

purpose of long term storage obtain a Class VI permit with some special consideration for the fact

that they are transitioning from a well not originally designed to meet Class VI requirements. The

Director has the authority to determine at what point a Class VI permit is required for those projects

that are transitioning from the primary purpose of EOR to long term storage of CO2. The final

regulation provides a set of technical factors for the Director to evaluate in making this

determination, at §144.19. EPA believes that this approach provides sufficient protection of USDWs

when there is an increased risk to USDWs as compared to traditional Class II operations while

allowing for site-specific flexibility. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

Commenter Name: Michele Schoepper Letter ID: 0503

Commenter Organization: American Petroleum Institute Comment ID: 21178

Comment: Additionally, by unnecessarily creating a regulatory gap between Class II Wells 

and operations and Class VI Wells and operations the EPA is creating a potential 

economic or operational barrier to transitioning from EOR operations to storage 

operations. Thereby further reducing the number of target formations where CO2 

could be stored. 

Response: EPA clarifies that the purpose of the GS rule is to ensure protection of USDWs from

endangerment and not to promote or incentivize GS deployment. However, the Agency believes that

establishing a regulatory framework for the future development and deployment of CCS technology

may provide the regulatory and jurisdictional certainty needed to foster development and deployment

of CCS while ensuring USDW protection. 

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 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 longterm 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 Clas II wells in thepreamble to the final GS rule.

Commenter Name: Matt Toner Letter ID: 0506

Commenter Organization: Hydrogen Energy International Comment ID: 21188

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: The existing Class II regulations governing injection of CO2 in oil and gas 

reservoirs have proven successful at protecting underground sources of drinking 

waters. These regulations should allow for the dual purpose of sequestration if 

anthropogenic CO2 is used. 

Hydrogen Energy also recommends that EPA expand grandfathering to facilitate 

transition from production and storage to storage only sites, which will 

incentive the use of these reservoirs for long-term CO2 storage. The proposed 

grandfathering of Class II Wells should go beyond just the construction 

requirements to include, at a minimum, operating and mechanical integrity 

requirements for existing, operationally compliant Class II EOR CO2 Injection 

Wells. The Class VI requirements would require technically unnecessary changes 

to equipment and monitoring procedures. 

Some authors have identified risks with using oil and gas reservoirs for CO2 

sequestration due to the presence of inactive wells. Proper plugging and 

abandonment of inactive wells is a prudent method which can ensure this risk is 

effectively managed. In addition, the oil and gas industry has developed 

techniques to quickly isolate, effectively repair, and remediate these issues 

and their unlikely occurrence. 

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

EPA agrees that many Class I, Class II, and Class V experimental technology wells are designed and

constructed to withstand exposure to CO2. The final GS rule allows the construction of these wells

to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director

that the wells were engineered and constructed to meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered because they Class II requirements are not tailored to

address the unique risks posed by long term CO2 storage to USDWs. Following re-permitting of the

project as GS, many of the unique factors of GS sites (e.g., increased reservoir pressures associated

with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water) will result in

an increased risk profile, warranting the specific requirements in the final GS rule.

Commenter Name: Matt Toner Letter ID: 0506

Commenter Organization: Hydrogen Energy International Comment ID: 21189

Comment: In closing, Hydrogen Energy would like to applaud EPA for their effort to create 

an effective regulatory framework for the injection and sequestration of carbon 

dioxide while protecting underground sources of drinking water. However, we 

believe that EPA should go significantly further than the proposed regulation by 

recognizing the potential for concurrent CO2 injection for enhanced oil and gas 

recovery and design storage in allowing for this dual purpose. 

Furthermore, EPA should facilitate grandfathering from dual purpose production 

and storage to storage only sites when enhanced oil or gas recovery operations 

are completed. 

Incentivizing the use of CO2 for enhanced oil and gas recovery would 

significantly reduce CO2 emissions. Currently, over 2 billion cubic feet of 

naturally occurring CO2 is used for enhanced oil recovery in the U.S. every day, 

and volumes are growing. 

Incentivizing anthropogenic CO2 would also increase U.S. energy security by 

facilitating additional EOR activity, and thereby reducing the need for foreign 

oil. Enhanced oil recovery has the potential to add 40 to 80 billion barrels of 

oil based on Department of Energy estimates. This volume is two to four times 

the current U.S. total crude reserves. 

Incentivizing the use of the anthropogenic CO2 would also effectively utilize 

proven well-studied and well-tested geologic storage containers. It will likely 

cost tens of millions of dollars and take several years of study to permit one 

commercial scale saline storage reservoir. Effectively utilizing gas, oil and 

gas for fields could also utilize over 100 years of oil field operating 

experience while building new confidence for future saving and storage options. 

Finally, this would also help kickstart the financially challenged carbon 
capture industry by improving economics and accelerating the uptake of this 

essential technology. Thank you very much. 

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

As described above, the final GS rule allows the construction of Class II wells to be grandfathered

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

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

in lieu of requirements at §146.86(b) and §146.87(a). Following re-permitting as Class VI wells,

these projects would be subject to the operational, MIT, monitoring, reporting, plugging, and postinjection site care and site closure requirements in the final GS rule. See the discussion of EPA's

final regulatory approach in the preamble to the GS rule for additional detail on these requirements.

EPA clarifies that the purpose of the GS rule is not to incentivize the use of GS or address energy

security. The purpose of the GS rule is to ensure that, where GS is deployed, it is conducted in a

manner that does not endanger USDWs. However, the Agency believes that establishing a regulatory

framework for the future development and deployment of CCS technology may provide the

regulatory and jurisdictional certainty needed to foster development and deployment of CCS while

ensuring USDW protection.

Commenter Name: Steve Crookshank Letter ID: 0523

Commenter Organization: American Petroleum Institute (API) Comment ID: 21361

Comment: Additionally while unnecessarily creating a regulatory gap between Class II 

wells and their operations and Class VI wells and their operations, EPA is 

creating potential economic and operational barrier to transitioning from EOR 

operations to storage operations thereby further reducing the number of target 

formations where CO2 can be stored. 

Response: Comments related to potential economic and operational barriers to trainsitioning EOR

operations to GS are outside the scope of this rulemaking. EPA clarifies that the purpose of the GS

rule is to ensure protection of USDWs from endangerment. However, the Agency believes that

establishing a regulatory framework for the future development and deployment of CCS technology

may provide the regulatory and jurisdictional certainty needed to foster development and deployment

of CCS while ensuring USDW protection.

Commenter Name: Leslie Glustrome Letter ID: 0527

Comment ID: 21409

Comment: EOR is not CCS. You put the CO2 under, you have no idea whether it stays under. 

Enhanced oil recovery is not CCS. Put the CO2 under, you have no idea whether it 
stays under the ground or not. There has been essentially no monitoring there 

and all we have to do is talk to the experts and they'll tell you that; no do 

not assume that EOR is CCS. It is a very different thing. 

Response: EPA agrees that the nature and risks of CO2 injection for long term storage is different

from Class II CO2 injection for EOR, and that tailored requirements for GS wells are appropriate and

necessary to protect USDWs from endangerment. For this reason, the Agency tailored UIC

requirements for Class VI wells that address the general risks deep injection may pose to USDWs

and specifically address the unique nature of CO2 GS (i.e., very large volumes, very long timeperiods, and reservoir pressure conditions). Owners and operators of Class VI wells are subject to the

operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure

requirements in the final GS rule. See the discussion of EPA's final regulatory approach in the

preamble to the GS rule for additional detail on these requirements.

Commenter Name: George Peridas Letter ID: 0534

Commenter Organization: Natural Resources Defense Council (NRDC) Comment ID: 21460

Comment: And the final technical point which might be somewhat outside the jurisdiction 

of the EPA, refer to this rulemaking is distinction between enhanced oil 

recovery and sequestration. This rule deals exclusively with deep saline 

formations and we believe that business as usual enhanced oil recovery should 

continue to be regulated as it always has under Class II. Nonetheless, if there 

are any changes, any significant changes in the over-riding conditions in oil 

fields where they inject CO2 which might well be the case if people see an 

economic incentive, to sequester larger amounts of CO2 in those oil fields. Then 

I believe that then, we will need to take a closer look at how these wells 

should be regulated and whether there is a need to regulate them under Class VI 

or to grandfather them with other appointments into Class VI and again the 

criteria, it should be whether we incur any significant changes in the risk 

profile of those injection as a result of trying to get more CO2 in there. 

Response: EPA agrees that tailored requirements for Class VI wells are necessary to address the

unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected from

endangerment. EPA also agrees that the nature and risks of CO2 injection for long term storage is

different from Class II CO2 injection for ER, and that tailored requirements for GS wells are

appropriate and necessary to protect USDWs from endangerment. For this reason, the Agency

tailored UIC requirements for Class VI wells that address the general risks deep injection may pose

to USDWs and specifically address the unique nature of CO2 GS (i.e., very large volumes, very long

time-periods, and reservoir pressure conditions). 

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule. 
Comment Code: 2048 1.5.2.4 Oppose Class VI/ Support Class V experimental technology well 

Individual Comments

Commenter Name: Michael H. Cochran Letter ID:

0108

Commenter Organization: Bureau of Water, Division of Environment, Kansas

Department of Health & Environment (KDHE)

Comment

ID: 21959

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: 144.18: Should be reworded along the lines of: upon the effective date of these 

regulations, new Class V wells must obtain a permit prior to construction. 

Response: EPA clarifies that any owner or operator seeking to construct an injection well must

obtain a permit before beginning injection, but not necessarily the construction of the well. Owners

and operators of Class VI wells for long-term sequestration or Class V experimental technology

wells (for experimental GS projects) must submit information about the well, the geology of the site,

and the planned injection to demonstrate to the Director that the project will be operated in a manner

that protects USDWs from endangerment.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24364

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 144.15 

Proposed CCS Group Recommendations: 4. Adding §144.15 to read as follows. 

§144.15 Prohibition of non-experimental Class V wells for geologic 

sequestration. 

The construction, operation or maintenance of any non-experimental Class V 

geologic sequestration well is prohibited.

Basis for CCS Group Comments: This provision should be deleted if EPA does limit 

Class VI wells to injection below the lowermost USDW in the final rule to allow 

Directors to selectively authorize GS in areas with USDWs below the injection 

zone. 

Response: The text at 144.15 is retained in the final regulation; the construction, operation or

maintenance of any non-experimental Class V GS well is prohibited under the final rule. The final

rule contains tailored requirements for Class VI wells to ensure that GS projects are permitted, sited,

constructed, operated, and closed in a manner that avoids releases of CO2 into USDWs.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24368
Comment: In addition, we recommend that all GS into basalts, coal seams, and salt domes 

be conducted under Class V as experimental wells initially and then as 

commercial scale Class V wells/projects if the experimental projects demonstrate 

that these sites can be suitable for geological sequestration while preventing 

endangerment of USDWs. 

Response: EPA expects that, after promulgation of the final rule, a limited number of Class V

experimental injection projects to test GS technology will continue, e.g., to inform the technology

associated with GS into basalts, coal seams, and salt domes. EPA clarifies that such projects are

experimental in nature and would be to test new technologies, and that EPA does not consider it

appropriate to permit CO2 injection wells that are testing the injectivity or appropriateness of an

individual formation (e.g., as a prelude to a commercial-scale operation) as Class V experimental

technology wells. Such wells should be permitted as Class VI wells. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. This

guidance will be available on EPA’s website at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24385

Comment: We recommend that all GS into basalts, coal seams, and salt domes be conducted 

under Class V as experimental wells initially and then as commercial scale Class 

V wells/projects if the experimental projects demonstrate that these sites can 

be suitable for geological sequestration while preventing endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain enough 

experience to develop suitable permitting requirements for such wells and to 

tailor those requirements at both the pilot and commercial scales until the 

agencies are ready to adapt the Class VI regulations. 

Response: EPA expects that, after promulgation of the final rule, a limited number of Class V

experimental injection projects to test GS technology will continue, e.g., to inform the technology

associated with GS into basalts, coal seams, and salt domes. EPA clarifies that such projects are

experimental in nature and would be to test new technologies, and that EPA does not consider it

appropriate to permit CO2 injection wells that are testing the injectivity or appropriateness of an

individual formation (e.g., as a prelude to a commercial-scale operation) as Class V experimental

technology wells. Such wells should be permitted as Class VI wells. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. This

guidance will be available on EPA’s website at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 
Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24392

Comment: We recommend that all GS into basalts, coal seams, and salt domes be conducted 

under Class V as experimental wells initially and then as commercial scale Class 

V wells/projects if the experimental projects demonstrate that these sites can 

be suitable for geological sequestration while preventing endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain enough 

experience to develop suitable permitting requirements for such wells and to 

tailor those requirements at both the pilot and commercial scales until the 

agencies are ready to adapt the Class VI regulations. 

Response: EPA expects that, after promulgation of the final rule, a limited number of Class V

experimental injection projects to test GS technology will continue, e.g., to inform the technology

associated with GS into basalts, coal seams, and salt domes. EPA clarifies that such projects are

experimental in nature and would be to test new technologies, and that EPA does not consider it

appropriate to permit CO2 injection wells that are testing the injectivity or appropriateness of an

individual formation (e.g., as a prelude to a commercial-scale operation) as Class V experimental

technology wells. Such wells should be permitted as Class VI wells. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. This

guidance will be available on EPA’s website at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24397

Comment: In addition, we recommend that all GS into basalts, coal seams, and salt domes 

be conducted under Class V as experimental wells initially and then as 

commercial scale Class V wells/projects if the experimental projects demonstrate 

that these sites can be suitable for geological sequestration while preventing 

endangerment of USDWs. 

Response: EPA expects that, after promulgation of the final rule, a limited number of Class V

experimental injection projects to test GS technology will continue, e.g., to inform the technology

associated with GS into basalts, coal seams, and salt domes. EPA clarifies that such projects are

experimental in nature and would be to test new technologies, and that EPA does not consider it

appropriate to permit CO2 injection wells that are testing the injectivity or appropriateness of an

individual formation (e.g., as a prelude to a commercial-scale operation) as Class V experimental

technology wells. Such wells should be permitted as Class VI wells. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. This

guidance will be available on EPA’s website at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 
Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24398

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.81(b) 

Proposed CCS Group Recommendations: (b) This subpart applies to wells used to 

inject carbon dioxide EXCLUSIVELY for the purpose of geologic sequestration, 

i.e., the long-term containment of a gaseous, liquid or supercritical carbon 

dioxide stream in subsurface geologic formations OTHER THAN OIL OR GAS 

RESERVOIRS, COAL SEAMS, BASALTS, OR SALT CAVERNS. 

Basis for CCS Group Comments: See 144.6 and the note immediately above about the 

requirement for conforming language. 

Deleted "gaseous, liquid or supercritical" because it was added to the 

definition of CO2 stream. 

Response: As described above, EPA expects that, after promulgation of the final rule, a limited

number of experimental injection projects to test GS technology will continue, e.g., to inform the

technology associated with GS into basalts, coal seams, and salt domes. Based on its evaluation of

all public comments and input on the proposed rule and NODA and Request for Comment, EPA has

made many revisions to the GS Rule. See the final rule and preamble for further discussion on EPA's

final approach.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24511

Comment: In conjunction with this recommendation, CSC also recommends that all GS into 

basalts, coal seams, and salt domes be conducted under Class V as experimental 

wells initially and then as commercial scale Class V wells/projects as the 

experimental projects or other factors allow applicants to demonstrate that 

these sites can be suitable for geological sequestration while preventing 

endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain 

experience in developing suitable permitting requirements for such wells and to 

tailor those requirements until the agencies are ready to adapt the Class VI 

regulations or other requirements as appropriate. 

Response: EPA expects that, after promulgation of the final rule, a limited number of Class V

experimental injection projects to test GS technology will continue, e.g., to inform the technology

associated with GS into basalts, coal seams, and salt domes. EPA clarifies that such projects are

experimental in nature and would be to test new technologies, and that EPA does not consider it

appropriate to permit CO2 injection wells that are testing the injectivity or appropriateness of an

individual formation (e.g., as a prelude to a commercial-scale operation) as Class V experimental

technology wells. Such wells should be permitted as Class VI wells. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental
technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. This

guidance will be available on EPA’s website at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Commenter Name: Neeraj Gupta Letter ID: 0229

Commenter Organization: Battelle Energy Technology (BET) Comment ID: 21812

Other EPA Comment Codes and Descriptions: 1850 1.4.2 CO2 GS Field Research 

Comment: Encouraging Innovation and Experimental Projects - We believe that USEPA 

recognizes that many facets of GS site selection, implementation, and monitoring 

are still under technological assessment and innovation phase. Many of the 

concepts and technological options are being evaluated under current field 

demonstration programs by Regional Partnerships and other projects across the 

world. The success of these existing and future experimental projects is 

heavily dependent on permitting process being as simple as possible. USEPA UIC 

Guidance 83 allowing the use of Class V experimental wells has been a very 

useful mechanism for facilitating experimental projects. In fact, if the 

proposed Class Vi framework was to be applied to smaller-scale tests currently 

underway, it is our belief that many projects would have financial, logistical, 

or technical difficulties in moving to field stage. With the proposed 

regulation in the public comment phase, MRCSP has already observed that the 

permit regulations for even small-scale field tests (such as MRCSP East Bend 

site and AEP Mountaineer Project) are becoming too onerous compared to similar 

projects permitted prior to the issuance of draft regulations. For example, the 

post-injection monitoring durations have become much longer with the regulators 

citing the draft regulation as a basis for requirements. Such a trend will 

certainly adversely affect future experimental projects and lead to less new 

data being available to all stakeholders. We strongly encourage EPA to 1) 

continue the existing option for using Class V experimental well permits option 

and/or specifically allow for a more simplified and less onerous permitting 

requirements for such project. 

Response: EPA acknowledges the value of the DOE pilot projects and resultant data and

information generated by such projects. EPA has evaluated permits and reviewed operational data

and information associated with the seven RCSPs funded by the U.S. Department of Energy and

coordinated through the National Energy Technology Laboratory (NETL). 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. 

The GS final rule does not affect an owner or operator’s ability to apply for a Class V experimental

technology well permit for projects that are of an experimental nature, i.e., to test GS technologies.

The Agency is also tracking operation and technical developments of more than three dozen smalland large-scale GS injection projects in the United States and abroad. EPA meets regularly with

DOE to discuss its research initiatives, project developments, and "best practices." 
EPA agrees with commenters that flexibility to address new research is important. Even after

finalizing the rule, 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.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24836

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: EPA Proposal: 4. Adding § 144.15 to read as follows. 

§ 144.15 Prohibition of non-experimental Class V wells for geologic 

sequestration. 

The construction, operation or maintenance of any non-experimental Class V 

geologic sequestration well is prohibited. 

GWPC Recommendations: This provision should be deleted if EPA does limit Class 

VI wells to injection below the lowermost USDW in the final rule to allow 

Directors to selectively authorize GS in areas with USDWs below the injection 

zone. 

In addition, it is recommended that all GS into basalts, coal seams, salt domes, 

and shales be conducted under Class V as experimental wells initially and then 

as commercial scale Class V wells/projects if the experimental projects 

demonstrate that these sites can be suitable for geological sequestration while 

preventing endangerment of USDWs. 

Rationale: Keeping these wells under Class V would allow EPA and the states to 

gain enough experience to develop suitable permitting requirements for such 

wells and to tailor those requirements until the agencies are ready to adapt the 

Class VI regulations. 

Response: The text at 144.15 is retained in the final regulation; the construction, operation or

maintenance of any non-experimental Class V GS well is prohibited under the final rule. The final

rule contains tailored requirements for Class VI wells to ensure that GS projects are permitted sited,

constructed, operated, and closed in a manner that does not endanger USDWs.

EPA also clarifies that the final GS rule does not categorically preclude injection of CO2 into any

formation types. Existing experimental GS projects may be permitted as described in UIC Program

Guidance #83: Using the Class V Experimental Technology Well Classification for Pilot Carbon

Geologic Sequestration Projects, which provided information for permitting authorities to consider

when permitting experimental GS projects (i.e., those projects that are designed to test new,

unproven technologies, per the definition of a Class V experimental technology well). EPA adds

that, following finalization of the GS rule, all GS projects that are not for experimental purposes

must be re-permitted as Class VI wells and be subject to the final GS requirements. EPA expects

that, after promulgation of the final rule, a limited number of experimental injection projects to test

GS technology will continue, e.g., to inform the technology associated with GS into basalts, coal
seams, and salt domes. 

The Agency also clarifies that it does not consider it appropriate to permit CO2 injection wells that

are testing the injectivity or appropriateness of an individual formation (e.g., as a prelude to a

commercial-scale operation) as Class V experimental technology wells. Such wells must be

permitted as Class VI wells.

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. This

guidance will be available on EPA’s website at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: John McManus Letter ID: 0294

Commenter Organization: American Electric Power Comment ID: 25307

Other EPA Comment Codes and Descriptions: 2200 1.6.4 Other formation types 

Comment: There is less technical support on the ability to conduct GS in basalts, coal 

seams, salt caverns, and shales. As compared with deep saline formations and 

hydrocarbon reservoirs, the trapping/containment mechanisms of CO2 and/or 

operational engineering involved in basalts, coal seams, salt caverns and shales 

may be significantly different and using identical regulatory language might not 

be appropriate. In fact, it is not known at this time whether GS (or even 

injection in some cases) can be done at commercial scale in each of these types 

of formations - GS efforts in these formations are still in the experimental 

stage. Wells in basalts, coal seams, salt caverns and shale formations should 

be treated as experimental wells under Class V, recognizing that completing the 

process of research, development and demonstration likely will require initial 

full scale experimental projects in addition to pilot projects. 

Keeping these wells under Class V would allow EPA and the states to gain enough 

experience to develop suitable permitting requirements for such wells and to 

tailor those requirements at both the pilot and commercial scales until the 

agencies are ready to regulate such wells under an appropriate class. 

Response: EPA clarifies that the final GS rule does not categorically preclude injection of CO2 into

any formation types. Experimental research projects will continue to be regulated as Class V

experimental technology wells as long as they remain of an experimental nature. EPA clarifies that

existing experimental GS projects may be permitted as described in UIC Program Guidance #83:

Using the Class V Experimental Technology Well Classification for Pilot Carbon Geologic

Sequestration Projects, which provided information for permitting authorities to consider when

permitting experimental GS projects (i.e., those projects that are designed to test new, unproven

technologies, per the definition of a Class V experimental technology well). EPA adds that,

following finalization of the GS rule, all GS projects that are not for experimental purposes must be

re-permitted as Class VI wells and be subject to the final GS requirements. EPA expects that, after

promulgation of the final rule, a limited number of experimental injection projects to test GS

technology will continue, e.g., to inform the technology associated with GS into basalts, coal seams,

and salt domes. 
EPA clarifies those Class V experimental projects subject to Guidance #83 will be those wells that

test new technologies for purposes of GS. The Agency also clarifies that it does not consider it

appropriate to permit CO2 injection wells that are testing the injectivity or appropriateness of an

individual formation (e.g., as a prelude to a commercial-scale operation) as Class V experimental

technology wells. Such wells must be permitted as Class VI wells.

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. This

guidance will be available on EPA’s website at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: John McManus Letter ID: 0294

Commenter Organization: American Electric Power Comment ID: 25308

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 2200 1.6.4 Other formation types 

Comment: To implement this approach, sections 144.6(f), 144.80(f), 146.5(f) and the 

definition of sequestration in 146.81 should be revised. The proposed 144.15 

provision that the construction, operation or maintenance of any nonexperimental Class V GS well is prohibited should be retained, but only with the 

understanding that this prohibition is not intended to limit the size or scale 

of any experimental GS operation. 

"Class VI. Wells used for geologic sequestration but not including those wells 

used for geologic sequestration that are regulated under another Class. Wells 

used for geologic sequestration in basalts, coal seams, salt caverns or shales 

are regulated under Class V as experimental wells until such time as the 

Administrator establishes separate requirements by rule for the specific type of 

formation or determines, following public notice and opportunity for comment, 

that wells used for geologic sequestration of carbon dioxide streams into the 

specific type of formation should be regulated under another class." 

Response: The text at 144.15 is retained in the final regulation; the construction, operation or

maintenance of any non-experimental Class V GS well is prohibited under the final rule. The final

rule contains tailored requirements for Class VI wells to ensure that GS projects are permitted, sited,

constructed, operated, and closed in a manner that protects USDWs from endangerment.

As described above, EPA clarifies that the final GS rule does not categorically preclude injection of

CO2 into any formation types. EPA clarifies that experimental research projects will continue to be

regulated as Class V experimental technology wells as long as they remain of an experimental

nature.

Comment Code: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment) 

Individual Comments
Commenter Name: Doug Louis Letter ID: 0121

Commenter Organization: Kansas Corporation Commission Comment ID: 22073

Comment: For states that will have existing CO2 rules. What will happen to projects that 

are permitted as Class V-experimental wells after the EPA passes its rule but 

before the states adopt EPA’s rules? Another concept that needs to be fully 

discussed is full-scale (not experimental) injection facilities that are applied 

for before the proposed EPA rules are adopted. How will they be permitted (i.e. 

what class) and who will permit them? The proposed rules should address these 

specific scenarios. 

Grandfathering Class II wells to Class VI wells. 

It is believed a great deal of potential storage of CO2 exists in EOR-CO2 floods 

after oil production ceases. It is my concern that EPA’s stringent standards for 

well cementing, monitoring and financial assurance will discourage oil operators 

using this additional pore space for sequestration, thus causing waste. If a 

Response: Experimental GS research projects will continue to be regulated as Class V experimental

technology wells as long as they remain of an experimental nature. EPA clarifies that existing

experimental GS projects may be permitted as described in UIC Program Guidance #83: Using the

Class V Experimental Technology Well Classification for Pilot Carbon Geologic Sequestration

Projects, which provided information for permitting authorities to consider when permitting

experimental GS projects (i.e., those projects that are designed to test new, unproven technologies,

per the definition of a Class V experimental technology well). EPA adds that, following finalization

of the GS rule, all GS projects that are not for experimental purposes must be re-permitted as Class

VI wells and be subject to the final GS requirements. EPA expects that, after promulgation of the

final rule, a limited number of experimental injection projects to test GS technology will continue,

e.g., to inform the technology associated with GS into basalts, coal seams, and salt domes. 

The Agency also clarifies that it does not consider it appropriate to permit CO2 injection wells that

are testing the injectivity or appropriateness of an individual formation (e.g., as a prelude to a

commercial-scale operation) as Class V experimental technology wells. Such wells must be

permitted as Class VI wells.

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. This

guidance will be available on EPA’s website at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

EPA clarifies that projects that are to become commercial immediately can be permitted as Class I

industrial well until the GS rule becomes effective. 

In response to the comment that ER operators will be discouraged from pursuing GS or using

additional pore space for storage is outside the scope of the rulemaking. EPA clarifies that the

purpose of the GS rule is not to incentivize the use of GS or to address the use of pore space but to

ensure that, where GS is deployed, it is conducted in a manner that does not endanger USDWs.

Furthermore, based on evaluation of available project data, EPA believes that the Class VI

requirements are not overly stringent and reflect the operation, monitoring, and modeling currently
conducted at several existing GS sites.

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24758

Other EPA Comment Codes and Descriptions: 2062 1.5.3.1 Grandfathering construction of Class

I wells (seeking comment); 2064 1.5.3.2 Grandfathering construction of Class II wells (seeking

comment); 2066 1.5.3.3 Grandfathering construction of Class V wells (seeking comment) 

Comment: Subpart H--Criteria and Standards Applicable to Class VI Wells 

§146.81 Applicability. 

(a) This subpart establishes criteria and standards for UIC programs to regulate 

Class VI CO2 GS injection wells. (b) This subpart applies to wells used to 

inject CO2 specifically for the purpose of GS, i.e., the long-term containment 

of a gaseous, liquid or supercritical CO2 stream in subsurface geologic 

formations. (c) This subpart applies to owners and operators of permit or ruleauthorized Class I industrial, Class II, or Class V experimental CO2 injection 

projects who seek to apply for a Class VI geologic sequestration permit for 

their well or wells. If the Director determines that USDWs will not be 

endangered, such wells are exempt, at the Director's discretion, from the casing 

and cementing requirements at §§146.86(b) and 146.87(a)(1) through (3). 

{RRC agrees that the Director evaluating a permit application to use existing 

injection wells for geologic sequestration should have the discretion to exempt 

wells from Class I industrial, Class II or Class V wells from the proposed 

casing and cementing requirements of Class VI wells. } 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c).

Commenter Name: John Hanger Letter ID: 0130

Commenter Organization: Pennsylvania Dept. of Env. Protection Comment ID: 21519

Comment: How Would This Proposal Affect Existing Injection Wells Under the UIC Program? 

-DEP and DCNR are concerned about the upgrading requirements necessary to 

grandfather existing EOR wells into the Class VI program. Historically, 

grandfathered installations such as wells have not been constructed to current 

standards and may not have adequate materials to meet the new requirements for 

injection. The standard of proof to demonstrate that an old well is adequate to 

be “grandfathered” should be high. The risk of needing remediation outweighs 

the inconvenience of upgrading an existing injection well. 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given
that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and corrosivity of CO2 in the

presence of water. The final GS rule provides that the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies that only

the construction reuirements are grandfathered and that all other Class VI requirements (reporting,

monitoring, mechnical integrity testing, etc.) must be met following a determination under

§146.81(c).

Commenter Name: Dawn A. Thorne Letter ID:

0134

Commenter Organization: University of Utah Energy and Geoscience Institute on

behalf of the Southwest Regional Partnership

Comment

ID: 21660

Comment: - Section 146.81(c) "This subpart applies to owners and operators of 

permit or rule-authorized Class I industrial, Class II, or Class V experimental 

carbon dioxide injection projects who seek to apply for a Class VI geologic 

sequestration permit for their well or wells. If the Director determines that 

USDWs will not be endangered, such wells are exempt, at the Director's 

discretion, from the casing and cementing requirements at .¢§ 146.86(b) and 

146.87(a)(I) through (3)." 

Response/Discussion: Only the casing and cementing requirements would be 

"grandfathered" into the Class VI permit if accepted by the EPA Director. The 

SWP recommends the consideration of grandfathering Class I, II, and V permits 

into the Class VI category on a site-specific basis. Many of the Class VI 

regulations mirror Class I, II, and V permit regulations, therefore, the time 

and budget it would require the owner/operator and EPA Director to re-permit an 

existing well may not be required. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides that the

construction of these wells be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

EPA disagrees with commenters who suggest that other requirements (outside of well construction)

should also be grandfathered. Following re-permitting of the project as GS, many of the unique

factors of GS sites (e.g., increased reservoir pressures associated with large volumes of stored CO2

and the corrosivity of CO2 in the presence of water) will result in an increased risk profile,

warranting the specific requirements in the final GS rule. Therefore, following re-permitting as Class

VI wells, these projects must be subject to the operational, MIT, monitoring, reporting, plugging, and

post-injection site care and site closure requirements in the final GS rule. See the discussion of

EPA's final regulatory approach in the preamble to the GS rule for additional detail on these

requirements.
Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22559

Comment: In some areas it is likely that existing wells will be converted into both 

injection wells and monitoring wells. It seems unlikely that such wells will 

have been constructed to the same standard as wells purpose-built for 

sequestration applications. This, however, is probably not reason enough to 

rule them out from being used as long as they meet the same standards for 

protection as new wells do. This said, there should be a cutoff date so that 

all wells used for CO2 injection or monitoring constructed after the date are 

constructed to the same standard. 

Response: EPA agrees that converted wells should be subject to Class VI requirements. Following

conversion of the project to GS, many of the unique factors of GS sites (e.g., increased reservoir

pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the presence of

water) will result in an increased risk profile and warrant the specific requirements in the final GS

rule. Projects that inject CO2 for the primary purpose of long term storage will be permitted as Class

VI wells and will be subject to the specific requirements in the final GS rule. The GS rule contains

tailored requirements that directly address issues unique to large-scale CO2 injection for GS.

The final GS rule provides that the construction of these wells be grandfathered per §146.81(c),

provided the owner or operator can demonstrate to the Director that the wells were engineered and

constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of

requirements at §146.86(b) and §146.87(a). EPA clarifies that only the construction reuirements are

grandfathered and that all other Class VI requirements (reporting, monitoring, mechnical integrity

testing, etc.) must be met following a determination under §146.81(c). 

EPA does not plan to institute a "cut off" date for this requirement since conversion is a site-specific

decision that may take place at different times then other conversions and it cannot be predicted with

certainty when all eligible ER fields in the US will have been transitioned for GS. EPA encourages

owners or operators and Directors to coordinate on re-permitted wells to ensure that all wells used

for GS are constructed and operated in a manner that protects USDWs from endangerment.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22577

Comment: Preamble Questions: EPA seeks comment on how the grandfathering approach for 

existing wells may affect compliance with the other requirements in its 

proposal. EPA Notice 50. 

NGWA Response: See NGW Comment Document (word document) Section titled 

"Classification of Injection Wells for Carbon Sequestration, Class II Injection 

Well Transition, and Grandfathering" for further details. 

Response: EPA disagrees that every GS well should initially be permitted as a Class V well, as

suggested by the commenter in the document on classification of injection wells for geologic

sequestration. The Agency believes that the tailored Class VI requirements including extensive

requirements for geologic site characterization at §146.82, AoR evaluation at §146.84, and testing of

the well during drilling at §146.87 are appropriate to ensure that permitting authorities have the

necessary information to evaluate whether a specific site will allow safe injection of CO2. EPA adds

that submittal and review of monitoring data (as required at §146.90) and the AoR reevaluation
process (§146.84(e)) will provide an opportunity for an ongoing review of the site and a dialogue

between the Director and the owner or operator to ensure that the project is being operated in a

manner that protects USDWs from endangerment. Given this approach to permitting Class VI

projects, EPA believes that the requirements for grandfathering of construction at §146.81(c) are

necessary and appropriate.

Commenter Name: Steven Pirner Letter ID: 0153

Commenter Organization: South Dakota Department of Environment and

Natural Resources

Comment ID:

22142

Comment: 146.81 Applicability (c) - exempts Class I, II, and V wells from having to do 

cement work-overs if wells protective of USDWs - this is good use of these other 

wells once their original use is completed 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides the construction

of these wells be grandfathered per §146.81(c), provided the owner or operator can demonstrate to

the Director that the wells were engineered and constructed to meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA

clarifies that only the construction requirements are grandfathered and that all other Class VI

requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met following a

determination under §146.81(c). 

The requirements of the GS rule apply once the project initiates long-term sequestration of CO2.

Commenter Name: James Childress Letter ID: 0158

Commenter Organization: Gasification Technologies Council (GTC) Comment ID: 23766

Comment: Concern #11 : Grandfathering of construction requirements at the Director's 

discretion for existing Class I, Class II, and Class V wells seeking to convert 

to Class VI wells and whether additional construction requirements would be 

necessary to Prevent endangerment to USDWs from the GS ofCO2. (Ref. page 43497, 

Sec. G) 

Requirements for conversion of any well to a Class VI well should be site and 

risk dependent. EPA should consider expanding grandfathering scope to more than 

construction requirements and not a-priori require that all other permitting 

requirements be redone. Existing permit holders should be allowed to provide 

data on the experience and characteristics of their site demonstrating that it 

is suitable for long-term storage of carbon dioxide without endangering 

underground sources of drinking water. This could be more acceptable with an end 

date for grandfathering wells (e.g., -operational before 2012). 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechanical integrity testing, etc.) must be met

following a determination under §146.81(c). 
EPA disagrees with commenters who suggest that other requirements (e.g., MITs, siting, monitoring,

operational, and AoR requirements) should also be grandfathered. Following re-permitting of the

project as GS, many of the unique factors of GS sites (e.g., increased reservoir pressures associated

with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water) will result in

an increased risk profile, warranting the specific requirements in the final GS rule. Therefore,

following re-permitting as Class VI wells, these projects would be subject to the operational, MIT,

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final

GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for

additional detail on these requirements.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23362

Comment: Grandfathering Requirements of Class I, II and V UIC Wells -- Pg. 31 

APPA believes that the state should be allowed to grandfather construction 

requirements for existing Class I, II, and V wells seeking a Class VI permit for GS 

of CO2 if the state believes that the Class V experimental well USDW protections 

are adequate. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that decisions regarding the appropriateness of grandfathering will be

made by the Director.

EPA clarifies that only the construction requirements are grandfathered and that all other Class VI

requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met following a

determination under §146.81(c).

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23404

Comment: Although there are significant similarities between the proposed requirements 

for Class VI wells and the existing requirements for Class I, II, and V wells 

under the UIC Program, APPA does not believe that there should be a presumed 

grandfathering of Class I, II and V for the Class VI as storage sites. APPA 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies that only

the construction requirements are grandfathered and that all other Class VI requirements (reporting,

monitoring, mechnical integrity testing, etc.) must be met following a determination under
§146.81(c).

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23410

Comment: Grandfathering Requirements of Class I, II, and V UIC Wells 

This is an extremely important issue as a few APPA members plan to invest 

substantial resources in developing and permitting Class V experimental CO2 

injection wells to help demonstrate the viability of large-scale commercial 

deployment of CO2 sequestration. Some of these may also be conducted as DOE/NETL 

or state research or demonstration projects to illustrate how CO2 can be 

separated and injected. Federal and state governments should encourage these 

research and demonstration efforts, as their success is critical to the largescale commercial deployment of CO2 sequestration. The opportunity to operate 

these wells on a regular basis after they have been shown to be effective on an 

experimental basis should be allowed to help encourage the substantial, upfront 

investment necessary to get these wells permitted. APPA believes that the state 

should be allowed to grandfather of construction requirements for existing Class 

I, II, and V wells seeking a Class VI permit for GS of CO2 if the state believes 

that the Class V experimental well USDW protections are adequate. Since most of 

these new Class V experimental permits appear to be mirror images of Class I 

programs, APPA does not see how this will be a problem. Id. at 43502 In the case 

where the Class V program mirrored the Class I program, grandfathering of 

requirements beyond those related to construction is both necessary and 

appropriate, particularly for Class V wells. As an initial point, it has already 

been determined through the permitting process that the operation of these Class 

V wells is protective of USDWs. See 40 C.F.R. § 144 et seq. Having made this 

determination, there should be a regulatory presumption that conversion of these 

wells for the exact same activity - at a larger scale and for an extended time 

period - under the Class VI program is also protective of USDWs. However, APPA 

acknowledges and believes that the EPA final rule should clearly state that this 

should be done with the understanding that grandfathering will not be allowed if 

the Director demonstrates that conversion of these Class V experimental wells to 

Class VI would jeopardize USDWs. 

Response: EPA agrees that, when the Regional Carbon Sequestration Partnership projects are no

longer of an experimental nature, they should be re-permitted as Class VI wells if they are to be used

for commercial-scale GS, and be subject to the Class VI requirements.

EPA is provides for the construction of Class V experimental technology wells to be grandfathered

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

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

in lieu of requirements at §146.86(b) and §146.87(a). EPA understands based on reviews of several

Class V pilot project permits, that many Class V experimental technology wells, including those used

in the RCSP projects, are specifically designed for injection of CO2 and are being built to Class I

non-hazardous well specifications, which should facilitate re-permitting as Class VI wells. EPA

clarifies that only the construction requirements are grandfathered and that all other Class VI

requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met following a

determination under §146.81(c). 
EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24215

Comment: Rule Provisions: 146.81(c) 

EPA Preamble Question: 3. EPA seeks comment on the approach to grandfather 

construction requirements at the Director’s discretion for existing Class I, 

Class II, and Class V wells seeking to convert to Class VI wells, and whether 

additional construction requirements would be necessary to prevent endangerment 

to USDWs from the GS of CO2. EPA Notice 43502. 

API Response: API supports this provision. Candidate Class I and Class V wells 

for grandfathering will have a demonstrated record of performance under their 

existing operations and MIT programs to demonstrate sound performance and 

adequacy of well integrity that can be used as a basis for conversion to the 

Class VI program. 

For Class II wells, API proposes that they remain under the Class II program 

when transitioning from EOR to GS. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c). 

EPA disagrees that wells transitioning from ER to GS should be regulated as Class II wells. During

and following this transitional phase, many of the unique factors of GS sites (e.g., increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water) will result in an increased risk profile, warranting the specific requirements in the

final Class VI rule.

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 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 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.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24216

Comment: Rule Provisions: 146.81(c) 

EPA Preamble Question: 4. Additionally, EPA seeks comment on how the 

grandfathering approach for existing wells may affect compliance with the other 

requirements in its proposal. EPA Notice 43502. 

API Response: All components of the existing wells with a proven record of 

performance should be grandfathered unless there are specific USDW endangerment 

concerns identified by the Director. See Comment above. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechanical integrity testing, etc.) must be met

following a determination under §146.81(c). 

EPA disagrees that other requirements should also be grandfathered. Following re-permitting of the

project as GS, many of the unique factors of GS sites (e.g., increased reservoir pressures associated

with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water) will result in

an increased risk profile, warranting the specific requirements in the final GS rule. Therefore,

following re-permitting as Class VI wells, these projects would be subject to the operational, MIT,

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final

GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for

additional detail on these requirements.

Commenter Name: James Rower Letter ID: 0173

Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23466

Comment: • Given the similarities between Class VI wells (as envisioned by the Proposal) 

and the existing requirements for those Class I and V wells permitted 

exclusively for CO2 injection, the Final Rule should allow grandfathering of 

construction and operating requirements for these existing wells seeking to 

become Class VI wells provided that it can be demonstrated that such carryingover of requirements will be protective of USDWs. 

Response: EPA agrees that many Class I and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule provides for the construction of

these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to

the Director that the wells were engineered and constructed to meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA
clarifies that only the construction requirements are grandfathered and that all other Class VI

requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met following a

determination under §146.81(c).

Commenter Name: James Rower Letter ID: 0173

Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23478

Comment: However, the Proposal's grandfathering provision does not go far enough. It is 

both necessary and appropriate to allow for grandfathering of requirements 

beyond those related to construction where this carrying-over of requirements 

can be done in a manner that is protective of USDWs. This is particularly true 

for the Class I and V wells developed solely for the injection of CO2. It has 

already been determined through the permitting process that the operation of 

these Class I and V wells is protective of USDWs. See 40 C.F.R. § 144 et seq. 

Having made this determination, there should be a regulatory presumption that 

conversion of these wells for the exact same activity albeit at a larger scale 

and for an extended period of time - under the Class VI program is also 

protective of USDWs, with the understanding that grandfathering will not be 

allowed if the Director demonstrates that conversion of these wells to Class VI 

would endanger USDWs. In other words, EPA should bear the burden of showing why 

continued operation of the CO2 injection activities under the Class VI program 

should not be allowed. 

To the extent that EPA can demonstrate that elements of the Class VI program not 

already incorporated into the pre-existing Class I or V permit are necessary to 

protect USDWs, Owners or Operators can be required to incorporate such elements 

into the Class VI permit. This approach would be preferable to a default 

wholesale application of the Class VI program requirements to Class I or V wells 

currently used for the same activity and already proven to be protective of 

USDWs. USWAG recommends that the Final Rule include a presumption that Class I 

and V CO2 injection wells be allowed to transition into Class VI wells based on 

existing conditions, while allowing the Director to incorporate additional 

elements into the Class VI permit if the Director can show that continued 

operation of the pre-existing well under the Class VI program would not be 

protective of USDWs. 

Response: EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and

AoR requirements) should also be grandfathered for Class V and I wells. Following re-permitting of

the well as Class VI, many of the unique factors of GS sites (e.g., increased reservoir pressures

associated with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water)

will result in an increased risk profile, warranting the specific requirements in the final GS rule.

Therefore, following re-permitting as Class VI wells, these projects would be subject to the

operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure

requirements in the final GS rule. See the discussion of EPA's final regulatory approach in the

preamble to the GS rule for additional detail on these requirements.

Commenter Name: Quinlan J. Shea Letter ID: 0177

Commenter Organization: Edison Electric Institute Comment ID: 23556

Comment: EEI is concerned with how existing CO2 injection wells should be treated in the 
final regulations. The rule‘s grandfathering provision should be as expansive 

as possible while balancing the need for protection of USDW, and thus EEI 

recommends two principal modifications to the proposed provision. First, a 

preferable approach to limiting the scope of grandfathering only to construction 

requirements is to expand the scope of available grandfathering for existing 

wells, given that the wells were constructed for injection of CO2 in the first 

instance. Further, rather than leave grandfathering to the discretion of the 

program director, a preferable approach is to allow grandfathering as a default 

rule unless the program director determines that, pursuant to specified 

criteria, the specific nature of the project renders it unsuitable for CO2 

storage. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c). 

EPA disagrees that this grandfathering should be a "default," or that other requirements should also

be grandfathered. Following re-permitting of the well as Class VI, many of the unique factors of GS

sites (e.g., increased reservoir pressures associated with large volumes of stored CO2 and the

corrosivity of CO2 in the presence of water) will result in an increased risk profile, warranting the

specific requirements in the final GS rule. Therefore, following re-permitting as Class VI wells,

these projects would be subject to the operational, MIT, monitoring, reporting, plugging, and postinjection site care and site closure requirements in the final GS rule. See the discussion of EPA's

final regulatory approach in the preamble to the GS rule for additional detail on these requirements.

Commenter Name: Quinlan J. Shea Letter ID: 0177

Commenter Organization: Edison Electric Institute Comment ID: 23601

Comment: G. Grandfathering Provisions 

The sixth general area of concern addressed in these comments involves how two 

categories of existing injection wells in particular should be treated in the 

final regulations. The first such category includes existing CO2 injection and 

storage wells that have been permitted as "experimental" wells under the Class V 

UIC regulations or pilot projects that have been permitted as industrial 

projects under the Class I UIC regulations. The second category of existing 

wells under consideration includes Class II wells that inject CO2 for purposes 

of EOR. 

EPA has proposed giving the UIC program discretion to "grandfather" the 

construction requirements for existing Class I, II and Class V wells where the 

UIC program director can determine that the wells will not endanger USDW. Such 

grandfathering is soundly justified, as these wells have been constructed 

specifically for injection and, particularly in the case of Class I and V wells 

associated with CCS pilot projects, for storage of CO2 and are suitable for the 
purpose for which they are designed; the promulgation of new regulations should 

not render them unfit for the purpose for which they were intended. Further, 

permittees of these wells presumably were required to satisfy the nonendangerment standard as part of the initial permitting process. 

However, the limited scope of the proposed grandfathering--with the sole 

exception of the construction requirements, operators would be required to 

satisfy all provisions of the Class VI permitting requirements--coupled with the 

fact that its use is left to the UIC program director‘s discretion, casts 

considerable doubt on its potential efficacy. First, under these circumstances, 

potential grandfathering likely would not provide the needed assurance--and thus 

the needed incentives--to project operators or investors that existing wells, 

or, perhaps more importantly, new wells that may be permitted before the 

proposed rules take effect, will remain viable wells from a regulatory 

perspective going forward. Under those circumstances, the potential risks of 

"first actor" status may well outweigh any potential benefits. For example, 

limiting grandfathering for Class I or V experimental wells to construction 

requirements risks greatly reducing incentives for operators to undertake such 

projects, as at some point in the future they will be required to assume a far 

more stringent slate of obligations (including onerous financial assurance 

requirements). Moreover, given many of the other proposed limitations on GS 

projects, such as the restrictions on receiving formations, grandfathering may 

prove impossible even for projects that were specifically designed to inject and 

store CO2. 

As noted above, wells permitted to inject and store CO2 have already been deemed 

safe and suitable for those purposes, and a determination has already been made 

that no endangerment is posed to USDW. Under these circumstances, leaving a 

grandfathering determination to the discretion of the program 

director--discretion that may be exercised where the director determines that 

there is no endangerment to USDW--is unnecessarily duplicative of existing 

requirements and limiting for project operators. The desired protection of 

USDW has already been established for these projects, and absent some change in 

circumstances, that protection will remain. Further, leaving grandfathering to 

the discretion of the program director could result in a decision that, as a 

practical matter, comes too late for it to be viewed as a legitimate option at 

the start of a project. 

The rules’ grandfathering provision should be as expansive as possible while 

balancing the need for protection of USDW, and thus EEI recommends two principal 

modifications to the proposed provision. First, a preferable approach to 

limiting the scope of grandfathering only to construction requirements is to 

expand the scope of available grandfathering for existing wells, given that the 

wells were constructed for injection of CO2 in the first instance. Further, 

rather than leave grandfathering to the discretion of the program director, a 

preferable approach is to allow grandfathering as a default rule unless the 

program director determines that, pursuant to specified criteria, the specific 

nature of the project renders it unsuitable for CO2 storage. 

Response: As described above, EPA agrees that many Class I, Class II, and Class V experimental
technology wells are designed and constructed to withstand exposure to CO2, and the final GS rule

provides for the construction of these wells to be grandfathered per §146.81(c), provided the owner

or operator can demonstrate to the Director that the wells were engineered and constructed to meet

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

§146.86(b) and §146.87(a). However, EPA disagrees that other requirements (e.g., MITs, siting,

monitoring, operational, and AoR requirements) should also be grandfathered because the Class I, II,

and V requirements are not tailored to address injection of large volumes of CO2 for long term

storage.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23812

Comment: the Class II program. It is also positive that EPA is proposing that Directors 

have authority to grandfather certain requirements for Class V experimental 

project wells and other wells (Class II) when they are converted to full scale 

Class VI wells. The Alliance suggests that EPA should consider whether 

grandfathering the existing siting, AoR, operations, and monitoring plans for 

Class II and Class V wells when they are converted to full scale Class VI wells 

would protect USDWs while avoiding additional regulatory burden. 

[FN6] Proposed Rule, 73 Fed. Reg. at p. 43,495. 

Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies that only the construction

requirements are grandfathered and that all other Class VI requirements (reporting, monitoring,

mechanical integrity testing, etc.) must be met following a determination under §146.81(c). 

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, and AoR requirements) should

also be grandfathered. Following re-permitting of the project as GS, many of the unique factors of

GS sites (e.g., increased reservoir pressures associated with large volumes of stored CO2 and the

corrosivity of CO2 in the presence of water) will result in an increased risk profile, warranting the

specific requirements in the final GS rule. Therefore, following re-permitting as Class VI wells,

these projects would be subject to the operational, MIT, monitoring, reporting, plugging, and postinjection site care and site closure requirements in the final GS rule. See the discussion of EPA's

final regulatory approach in the preamble to the GS rule for additional detail on these requirements.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23866

Comment: wells. The CCS Alliance also supports EPA's proposal to provide Directors the 

authority to grandfather the construction requirements for Class V experimental 

project wells and other wells when they are converted to full scale Class VI 

wells. The Alliance suggests that EPA should consider whether grandfathering the 

existing siting, AoR, operations, and monitoring plans for Class II and Class V 

wells when they are converted to full scale Class VI wells would protect USDWs 

while avoiding additional regulatory burden. 
Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies that only the construction

requirements are grandfathered and that all other Class VI requirements (reporting, monitoring,

mechanical integrity testing, etc.) must be met following a determination under §146.81(c). 

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, and AoR requirements) should

also be grandfathered. Following re-permitting of the project as GS, many of the unique factors of

GS sites (e.g., increased reservoir pressures associated with large volumes of stored CO2 and the

corrosivity of CO2 in the presence of water) will result in an increased risk profile, warranting the

specific requirements in the final GS rule. Therefore, following re-permitting as Class VI wells,

these projects would be subject to the operational, MIT, monitoring, reporting, plugging, and postinjection site care and site closure requirements in the final GS rule. See the discussion of EPA's

final regulatory approach in the preamble to the GS rule for additional detail on these requirements.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23651

Comment: In its comments, AWWA makes several recommendations for the following specific 

items to be included in the final regulation: 

- Requirement for owner/operators of grandfathered wells to certify that the 

wells were constructed and cemented with materials appropriate for GS wells; 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23684

Comment: EPA Request for Comment: EPA seeks comment on the approach to grandfather 

construction requirements at the Director’s discretion for existing Class I, 

Class II, and Class V wells seeking to convert to Class VI wells, and whether 

additional construction requirements would be necessary to prevent endangerment 

to USDWs from the GS of CO2. EPA Notice 43502. 

AWWA Response: The construction requirements for the other well classes may not 

be as stringent as the requirements for Class VI wells. AWWA recommends that in 

order for wells from the other classes to be used for the injection of carbon 

dioxide, the wells must have been constructed using methods that are at least or 

more stringent than the Class VI requirements. Otherwise, as stated previously, 

it may encourage companies to construct an EOR well under the less strict Class 
II rules, with the goal of running the operation for a few years and then 

converting to a carbon sequestration operation. 

Certain operating methods for Class II wells may result in conditions that would 

be unacceptable for geologic sequestration. For example, EOR wells that used 

saltwater may be deteriorated to a point that would not be acceptable for the 

injection of carbon dioxide for geologic sequestration. In this case, these 

wells may have been constructed using different methods and materials that are 

not compatible with carbon dioxide. AWWA recommends that the owner/operators are 

required to prove that the grandfathered wells were constructed using corrosion 

resistant materials, and were cemented along the casing in accordance with the 

Class VI requirements. The well should be inspected to determine if any interior 

or exterior corrosion had occurred, and if so, there should be a determination 

that the well is not acceptable for use as a Class VI well. The review process 

should also include long-term demonstration by the owner/operator of the 

performance of the well as a Class II well. This review could provide an 

indication of continued prevention of USDW contamination. While these are fairly 

strict requirements, following this process is essential to prevent the 

contamination of USDWs or other source water aquifers. This should be the 

ultimate goal of the grandfathering process, not the prevention of additional 

construction costs for the owner/operator. 

Response: As described above, EPA agrees that a cautious approach to grandfathering is

appropriate, particularly given that the converted well will be used for a substantially different

process, which involves increased reservoir pressures associated with large volumes of stored CO2

and the corrosivity of CO2 in the presence of water. The final GS rule provides for the construction

of these wells to be grandfathered (per 146.81(c)). EPA has included a requirement in the final GS

rule that owners or operators seeking to convert existing wells for long term storage must

demonstrate to the Director that the grandfathered wells were engineered and constructed meet the

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

and §146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all

other Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c).

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23685

Other EPA Comment Codes and Descriptions: 4200 2.4.2 Down-hole shut-off valves in GS wells

(seeking comment) 

Comment: AWWA Response: Grandfathered wells may not have some of the protective measures 

that are required in the proposed regulation, such as the down-hole shut-off 

valve. This valve is an important safety mechanism and AWWA believes that a 

Class VI well should not be permitted for carbon sequestration unless it is 

constructed with this appurtenance. Also, some of the potentially grandfathered 

Response: EPA believes that some wells can be re-permitted for use as Class VI wells and safely

operated, even if down-hole shut-off systems cannot be installed. 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. However, the Agency believes that offshore Class VI wells present

unique construction and operational conditions, including isolation from shorelines and the need to

construct wells through the water column and the subsurface, which may delay response time in the

event of well difficulties. The rule requires, at §146.88(e)(3), that owners or operators of offshore

wells within State territorial waters install automatic down-hole shut-off systems. EPA believes that

these requirements at §146.88(e) ensure that proper precautions are taken to prevent subsurface fluid

movement and ensure protection of USDWs. 

The final GS regulation requires at §146.81(c) that owners or operators seeking to grandfather

existing Class I, II, or V 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). In addition, these grandfathered wells would still be

required to meet the other requirements of the GS regulation (e.g., operating, monitoring, MIT, well

plugging, and post-injection site care and site closure requirements).

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23686

Other EPA Comment Codes and Descriptions: 4500 2.5 Proposed Mechanical Integrity Testing

(MIT) Requirements (40 CFR 146.89) 

Comment: constructed with this appurtenance. Also, some of the potentially grandfathered 

wells may not be constructed in a way that would allow for the mechanical 

integrity testing requirements that are part of the regulation. AWWA believes 

that some of the very prescriptive testing and monitoring requirements are 

necessary, as the grandfathered wells may not have been constructed in a way 

that would allow for these tests to be carried out. AWWA recommends that EPA 

include in the final regulation a requirement that the owners/operators of the 

wells conclusively prove that the grandfathered wells can be operated in 

compliance with all the other requirements of the proposed regulation or the 

wells will not be permitted for Class VI operation. 

Response: EPA agrees with the commenter regarding the need for MITs; the final rule requires both

internal and external mechanical integrity testing. Mechanical integrity testing is one of the

cornerstones of the existing EPA UIC program. MIT requirements at §146.89 ensure protection of

USDWs from endangerment and provide an important early warning of potential problems in the

injection well. Routine mechanical integrity testing of injection wells provides data that enables the

identification and remediation of well integrity problems before they lead to leakage and/or

endangerment of USDWs. 

EPA agrees that a cautious approach to grandfathering is appropriate, particularly given that the

converted well will be used for a substantially different process. The final GS rule provides for the

construction of these wells to be grandfathered (per 146.81(c)). EPA has included a requirement in

the final GS rule that owners or operators seeking to convert existing wells for long term storage

must demonstrate to the Director that the grandfathered wells were engineered and constructed meet

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

§146.86(b) and §146.87(a). EPA clarifies that only the construction requirements are grandfathered

and that all other Class VI requirements (reporting, monitoring, mechanical integrity testing, etc.)

must be met following a determination under §146.81(c). 
EPA adds that following re-permitting as Class VI wells, these projects would be subject to the

requirements of the final GS rule, including MIT, monitoring, operational, reporting, plugging, and

post-injection site care and site closure requirements. See the discussion of EPA's final regulatory

approach in the preamble to the GS rule for additional detail on these requirements.

Commenter Name: Wendy Jacobs Letter ID: 0183

Commenter Organization: Harvard Law School Environmental Law and Policy

Center

Comment ID:

25165

Comment: V. EPA Should Not Allow, or Should At Least Severely Restrict, Grandfathering of

Existing Wells.

Under proposed 40 C.F.R. § 146.81(c), "[i]f the Director determines that USDWs

will not be endangered," existing Class I and II wells and Class V experimental

GS wells may be used for large-scale GS under the Class VI regulations but "are

exempt, at the Director’s discretion, from the casing and cementing requirements

at [proposed] §§ 146.86(b) and 146.87(a)(1) through (3)." See also 73 Fed. Reg.

at 43,502 (discussing how the grandfathering proposal "requires that the owner

or operator make a demonstration that the well will maintain integrity and

stability in a CO2 rich environment for the life of the GS project"). All wells

would need to meet all other requirements for Class VI wells, including the area

of review and site characterization, operating, monitoring, mechanical

integrity, well plugging, post-injection site care, and site closure

requirements. Id.

As EPA points out, "GS projects are anticipated to have long lifespans in

comparison to other types of deep injection wells. Not only must GS 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."

Id. at 43,510. In terms of construction materials, it appears from EPA’s

discussion that the selection of the cement and metal well materials is of

central importance given the potential of the CO2 stream (including water and

impurities) to corrode cement and metal well components. See id. at 43,509.

Therefore, proposed 40 C.F.R. § 146.86(b)(1) requires that "[a]ll well materials

must be compatible with fluids with which the materials may be expected to come

into contact and meet or exceed standards developed for such materials by the

American Petroleum Institute, ASTM International, or comparable standards

acceptable to the Director." [T]he owner or operator must provide [the Director]

the following information [including] Corrosiveness of the carbon dioxide

stream, and formation fluids; [and] [t]ype or grade of cement ..." Id. at

43,537-38 (proposed 40 C.F.R. § 146.86(b)(1)). EPA concludes that "[t]he

quality of the well materials, proper well construction, composition and

placement of appropriate cement along the wellbore, and appropriate maintenance

are crucial, because a leaking annulus would be a significant route of escape

for CO2." Id. at 43,509(emphasis added).

It is not clear why bypassing the "crucial" safeguards of proposed 40 C.F.R. §

146.86(b) and 146.87(a)(1) through (3) in favor of the Director’s general

determination that use of the well would not endanger USDWs is a good idea. See

73 Fed. Reg. at 43,535 (Proposed 40 C.F.R. § 146.81(c)). The need to
"grandfather" implies that the existing wells would not necessarily meet EPA’s

proposed construction standards for Class VI wells.[FN18] To the extent that

the specific proposed casing and construction requirements for GS wells provide

assurance beyond "no endangerment of USDWs," that "extra" assurance seems

appropriate in light of industry’s inexperience with large- scale, long-term GS

of CO2 and should be preserved. EPA has not articulated any justification for

why grandfathering is necessary. See 73 Fed. Reg. at 43,502.

[FN18] The construction requirements for Class I hazardous waste injection wells

include similar language to the Class VI standards. For example, "[a]ll well

materials must be compatible with fluids with which the materials may be

expected to come into contact. A well shall be deemed to have compatibility as

long as the materials used in the construction of the well meet or exceed

standards developed for such materials by the American Petroleum Institute, The

American Society for Testing Materials, or comparable standards acceptable to

the Director." 40 C.F.R. §146.65(b). However, the Class I well would have been

evaluated for "compatibility" with respect to the waste that was initially

injected into the well, which may be less (or more) corrosive than CO2 to the

particular well materials used to construct the well. Thus, the Class I

requirements would not necessarily ensure compatibility with CO2.

If grandfathering is permitted, EPA should limit its availability so as to not

create an unintended loophole from Class VI construction requirements. EPA

should require the Director to engage in a rigorous review of the design,

purpose, and suitability of the original well before allowing grandfathering in

any particular case. Also, grandfathering should only be allowed (if at all)

for existing Class I, II or GS Class V wells that are in operation as of the

final date of adoption of the GS regulations. If a well owner or operator

anticipates using a well constructed after that date for GS at any point in the

future, he or she should be required to plan accordingly and use the well

materials required by the most protective applicable standard.

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA clarifies that only the construction requirements will be grandfathered under the final GS rule;

following re-permitting as Class VI wells, these projects are subject to the operational, MIT,

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final

GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for

additional detail on these requirements.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation Comment ID:
Div. of Mineral Resources 25175

Comment: E. EPA seeks comment on the approach to grandfather construction requirements at 

the Director’s discretion for existing Class I, Class II, and Class V wells 

seeking to convert to Class VI wells, and whether additional construction 

requirements would be necessary to prevent endangerment to USDWs from the GS of 

CO2. 

NYSDEC-DMN Response: The Director should have the flexibility to determine 

whether a well meets federal Class VI protective standards on a well-by-well 

basis, and require the operator to adhere to the permitting process. 

Response: EPA believes that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). Conversion of the well

is at the Director's discretion following an evaluation of all other site-specific information about the

well and the project, e.g., modeling, monitoring, and other data. Any wells that have deteriorated due

to contact with incompatible injected or formation fluids may not be approved for conversion.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25176

Comment: F.Additionally, EPA seeks comment on how the grandfathering approach for 

existing wells may affect compliance with the requirements in this proposal. 

NYSDEC-DMN Response: The Director should have the flexibility to determine 

whether a well meets federal Class VI protective standards on a well-by-well 

basis, and require the operator to adhere to the permitting process. 

Response: EPA believes that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). Conversion of the well

is at the Director's discretion following an evaluation of all other site-specific information about the

well and the project, e.g., modeling, monitoring, and other data. Any wells that have deteriorated due

to contact with incompatible injected or formation fluids may not be approved for conversion. 

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25187
Other EPA Comment Codes and Descriptions: 3800 2.3 Proposed Injection Well Construction

Requirements (40 CFR 146.86) 

Comment: P. EPA also seeks comment on how the proposed grandfathering provisions for 

existing wells (construction requirements) may affect compliance with the above, 

proposed construction requirements. 

NYSDEC-DMN Response: NYSDEC-DMN believes that Director discretion is appropriate 

and necessary when reviewing other UIC Class wells for use as UIC Class VI 

wells. Overly prescriptive well construction requirements without any mechanism 

for deviation may limit the use of existing UIC wells and possible sequestration 

sites. 

Response: As described above, conversion of the well would be at the Director's discretion

following an evaluation of all other site-specific information about the well and the project, e.g.,

modeling, monitoring, and other data. Any wells that have deteriorated due to contact with

incompatible injected or formation fluids may not be approved for conversion.

EPA believes that, given the range of types of existing wells that may be candidates for conversion,

flexibility is appropriate regarding conversion of Class I, II, or V wells for GS, provided it can be

demonstrated to the Director's satisfaction that the converted well can conduct GS operations in a

manner that does not endanger USDWs. The final GS rule, at §146.81(c), allows the construction of

these wells to be grandfathered, provided the owner or operator can demonstrate to the Director that

the wells were engineered and constructed to meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). Only the cemented-inplace construction requirements would be grandfathered under the final GS rule; following

conversion, these wells must be permitted as Class VI wells and be subject to the operational, MIT,

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final

GS rule. 

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

will assist Directors and owner/operators in evaluating where a project may fit within a Class II to

Class VI transition. The guidance describes the methods available for the Director to determine the

risk posed to USDWs from a GS/ER project, and how the Director may determine if a project should

be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's web

site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Daniel Plath Letter ID: 0188

Commenter Organization: NiSource, Inc. Comment ID: 25234

Comment: As discussed above, addressing these two issues aggressively as proposed by EPA 

will significantly ensure the confinement of the CO2. The corollary is that it 

would not be in the interest of USDW protection or GS's acceptance by the public 

for EPA to grandfather well construction practices that are significantly below 

the standard set forth in the Proposed Rule so as to permit the conversion of a 

different UIC Class well to Class VI. Simply put, if the operator can not 

recondition the wells to substantially meet the rigorous standards as set forth 

in the Final Rule for technical, financial or other reasons, then the wells 

should not be used for GS. While Section 146.81(c) does not specifically 

indicate an automatic grandfathering of Class I, II, or V wells for Class VI, it 

should be clear that the phrase "...at the Director's discretion ..." means that 
the wells will have to substantially or virtually meet the "Injection Well 

Construction Requirements" in Section 146.86 and not simply meet some limited 

portion of those requirements. 

While NiSource will be advocating for greater flexibility in other sections in 

its comments, NiSource recommends caution on the issue of grandfathering well 

construction practices. 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule allows provides for the construction of these wells to be

grandfathered (per 146.81(c)). EPA has included a requirement in the final GS rule that owners or

operators seeking to convert existing wells for long term storage must demonstrate to the Director

that the grandfathered wells were engineered and constructed meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA

clarifies that only the construction requirements are grandfathered and that all other Class VI

requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met following a

determination under §146.81(c). EPA disagrees that this requirement "lowers the standard" for GS

wells. Conversion of the well would be at the Director's discretion following an evaluation of all

other site-specific information about the well and the project, e.g., modeling, monitoring, and other

data. Any wells that have deteriorated due to contact with incompatible injected or formation fluids

may not be approved for conversion.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24399

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.81(c) 

Proposed CCS Group Recommendations: (c) This subpart applies to owners and 

operators of permit or rule-authorized Class I industrial, Class II WHICH HAVE 

CEASED AND WILL NO LONGER BE USED FOR ENHANCED RECOVERY OF OIL OR

NATURAL GAS, 

or Class V experimental carbon dioxide injection projects who seek to apply for 

a Class VI geologic sequestration permit for their well or wells. If the 

Director determines that USDWs will not be endangered, such wells are exempt, at 

the Director’s discretion, from the casing and cementing requirements at §§ 

146.86(b) and 146.87(a)(1) through (3). CLASS VI REQUIREMENTS OF SUBPART H OF 

THIS PART. WELLS CONSTRUCTED IN ACCORDANCE WITH THE CLASS II

REQUIREMENTS OF § 

146.22 AND USED IN CO2 SERVICE AND THAT HAVE DEMONSTRATED MIT ARE

EXEMPT FROM THE 

REQUIREMENTS AT §§146.86 AND 146.87. 

Basis for CCS Group Comments: For first part, see 144.6 and the note above about 

the requirement for conforming language. 

Added language for transition of Class II wells to Class VI operations. These 
wells should be allowed based on their history of sound performance under the 

Class II program as demonstrated by MIT results. The language also allows the 

Director to exercise discretion to exempt other Class VI requirements. 

Response: EPA disagrees that other requirements (e.g., monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the project as GS, many of

the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Following re-permitting as Class

VI wells, these projects must be subject to the operational, MIT, monitoring, reporting, plugging, and

post-injection site care and site closure requirements in the final GS rule. See the discussion of

EPA's final regulatory approach in the preamble to the GS rule for additional detail on these

requirements.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24508

Comment: Rule Provisions or Federal Register Cite: 146.81(c) 

EPA Preamble Question: 3. EPA seeks comment on the approach to grandfather 

construction requirements at the Director’s discretion for existing Class I, 

Class II, and Class V wells seeking to convert to Class VI wells, and whether 

additional construction requirements would be necessary to prevent endangerment 

to USDWs from the GS of CO2. EPA Notice 43502. 

CSC Response: CSC strongly supports a regulatory approach that would facilitate 

the transition of existing wells constructed to Class I, Class II and Class V 

standards to GS wells regulated under provisions of the proposed rule. In all 

cases, such existing wells will have been permitted under conditions sufficient 

to protect USDWs and will have a demonstrated record of performance under their 

existing operations and MIT programs that can be used as a basis for conversion 

to the Class VI program or (in the case of GS wells in depleted oil and gas 

reservoirs) to enhanced Class II requirements. In particular, wells constructed 

to current Class II standards with demonstrated success in CO2 service should be 

eligible for grandfathering with minimal steps such as notification and permit 

modifications to add any additional requirements necessary to address geologic 

containment of injected carbon dioxide streams. Wells with this performance 

record should not require any additional structural requirements to ensure 

protection of USDWs because of their demonstrated success. 

Rule Provisions or Federal Register Cite: 146.81(c) 

EPA Preamble Question: 4. Additionally, EPA seeks comment on how the 

grandfathering approach for existing wells may affect compliance with the other 

requirements in its proposal. EPA Notice 43502. 

CSC Response: All components of the existing wells with a proven record of 

performance should be grandfathered unless there are specific USDW endangerment 

concerns identified by the Director. See Comment above. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the
construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

As described above, EPA disagrees that other requirements (e.g., MITs, siting, monitoring,

operational, and AoR requirements) should also be grandfathered. Following re-permitting, these

projects must be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection

site care and site closure requirements in the final GS rule. See the discussion of EPA's final

regulatory approach in the preamble to the GS rule for additional detail on these requirements.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24570

Comment: Rule Provisions: 146.81(c) 

EPA Rule Issue: 3. EPA seeks comment on the approach to grandfather construction 

requirements at the Director’s discretion for existing Class I, Class II, and 

Class V wells seeking to convert to Class VI wells, and whether additional 

construction requirements would be necessary to prevent endangerment to USDWs 

from the GS of CO2. EPA Notice 43502. 

Anadarko Petroleum Corporation (APC) Response: APC strongly supports this 

provision. Candidate Class I and Class V wells for grandfathering will have a 

demonstrated record of performance under their existing operations and MIT 

programs to demonstrate sound performance and adequacy of well integrity that 

can be used as a basis for conversion to the Class VI program. 

For Class II wells, APC, along with the Multi- Stakeholder Discussion Group, 

propose that they remain under the Class II program when transitioning from EOR 

to GS. Through the approach of two forms of sequestration, Class VI and Class II 

GS, the EPA would eliminate some of the future confusion regarding 

grandfathering of requirements. EOR wells will have proven their integrity and 

protection of USDWs during the operational phases of the flood through sound 

performance and MIT programs; and, therefore, the construction requirements 

proposed will not be necessary. 

In addition, many of the required well construction requirements, such as cement 

to surface, are truly not necessary. Industry has proven the successfulness of 

current well cement practices in 35 plus years of CO2 injection for EOR with an 

excellent environmental, health, and safety record. Through keeping these 

projects in the same regulating agency that governed the EOR operations it 

ensures that those regulators the most knowledgeable for working in oil and gas 

reservoirs are overseeing the regulatory requirements. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).
EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the project as GS, many of

the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24571

Comment: Rule Provisions: 146.81(c) 

EPA Rule Issue: 4. Additionally, EPA seeks comment on how the grandfathering 

approach for existing wells may affect compliance with the other requirements in 

its proposal. EPA Notice 43502. 

Anadarko Petroleum Corporation (APC) Response: All components of the existing 

wells with a proven record of performance should be grandfathered unless there 

are specific USDW endangerment concerns identified by the Director. Projects 

that are being converted to sequestration projects will have a significantly 

larger base-line data set than those pure sequestration projects. This should be 

taken into account when considering grandfathering provisions and plan 

requirements. See Comment above. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

As described above, EPA disagrees that other requirements (e.g., MITs, siting, monitoring,

operational, and AoR requirements) should also be grandfathered. Following re-permitting, these

projects must be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection

site care and site closure requirements in the final GS rule. See the discussion of EPA's final

regulatory approach in the preamble to the GS rule for additional detail on these requirements.

Commenter Name: John Corra Letter ID: 0205

Commenter Organization: Wyoming Department of Environmental Quality

(DEQ)

Comment ID:

22200

Comment: 6. Various issues where we agree with US EPA that the Director should have the 

discretion to determine, or require: 

a. Grandfathering the construction requirements for existing Class I and Class 

II wells seeking a permit for geologic sequestration of CO2, provided that they 

conform to Class VI requirements as proposed in the regulation. 
Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule allows the construction of

these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to

the Director that the wells were engineered and constructed to meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA

clarifies that only the construction requirements are grandfathered and that all other Class VI

requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met following a

determination under §146.81(c). 

Conversion of the well is at the Director's discretion following an evaluation of all other site-specific

information about the well and the project, e.g., modeling, monitoring, and other data under §146.81.

Any wells that have deteriorated due to contact with incompatible injected or formation fluids may

not be approved for conversion.

Commenter Name: Michael Stroben Letter ID: 0209

Commenter Organization: Duke Energy Comment ID: 22683

Comment: GRANDFATHERING CLASS I, CLASS II AND CLASS V INJECTION WELLS 

Duke Energy supports EPA’s proposed provision allowing for the potential 

grandfathering of construction requirements for permitted Class I, Class II and 

Class V wells that request a class VI permit for GS of CO2. Duke Energy also 

recommends that grandfathering be expanded beyond construction for Class V 

experimental CO2 injection wells. 

The permitting of experimental wells includes making a determination about the 

protection of underground sources of drinking water ("USDW"). Changing wells 

from experimental to regular injection of CO2 should not change the 

determination. Owners/operators of experimental wells that wish to have them 

reclassified as Class VI injection wells should be allowed to do so with minimal 

addition submittals. However, if the Director determines that conversion of a 

well to Class VI would endanger USDW, grandfathering should not be permitted. 

Duke Energy recognizes that there are differences between Class II and Class V 

wells. Class II wells are associated with enhanced oil and gas recovery. The 

strata that contained the oil and gas for millions of years should be good 

candidates for GS of CO2. While long term GS of CO2 was not the goal during the 

permitting of Class I wells, the Director should nonetheless consider 

grandfathering them for reclassification to Class VI wells. Owners/operators of 

Class II wells used for long-term GS of CO2 would still need to demonstrate that 

doing so would not pose a danger to USDW. Before a Class II well is permitted as 

a Class VI well, however, the owner/operator should be required to meet all 

other permitting requirements for a Class IV well. 

The construction requirements for Class I wells is very similar to what EPA 

proposes for Class VI wells. Duke Energy feels that once the integrity and 

stability of the well have been demonstrated in a CO2 rich environment by the 

owner/operator the construction of a Class I well should be grandfathered. As 

with Class II wells, all other requirements for a Class VI well would have to be 
met before an injection permit would be issued. 

Duke Energy recommends that the Final Rule allow permitted Class V experimental 

CO2 injection wells to be re-classified as Class VI wells based on initial 

permitting information unless the Director determines that the project would 

endanger USDWs. Class II wells should be considered for reclassification once 

all requirements for a Class VI well are met. Class I well construction should 

be grandfather upon demonstration that the well construction has and will 

maintain mechanical integrity while being used for GS of CO2. All other 

requirements of the final rule would apply for reclassification to Class VI. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the project as GS, many of

the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

Commenter Name: Richard Guinn Letter ID: 0210

Commenter Organization: Eastman Chemical Company Comment ID: 22702

Comment: 11. Requirements for conversion of any well to a Class VI well should be site 

and risk dependent. 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies that only

the construction requirements are grandfathered and that all other Class VI requirements (reporting,

monitoring, mechnical integrity testing, etc.) must be met following a determination under

§146.81(c). Conversion of the well is at the Director's discretion following an evaluation of all other

site-specific information about the well and the project, e.g., modeling, monitoring, and other data.

EPA expects that any wells that have deteriorated due to contact with incompatible injected or

formation fluids would not be approved for conversion.
Commenter Name: Richard Guinn Letter ID: 0210

Commenter Organization: Eastman Chemical Company Comment ID: 22717

Comment: Concern #11: Grandfathering of construction requirements at the Director’s 

discretion for existing Class I, Class II, and Class V wells seeking to convert 

to Class VI wells, and whether additional construction requirements would be 

necessary to prevent endangerment to USDWs from the GS of CO2. (Ref: page 43497, 

Sec. G) Requirements for conversion of any well to a Class VI well should be 

site and risk dependent. EPA should consider expanding grandfathering scope to 

more than construction requirements and not a-priori require that all other 

permitting requirements be redone. Existing permit holders should be allowed to 

provide data on the experience and characteristics of their site demonstrating 

that it is suitable for long-term storage of carbon dioxide without endangering 

underground sources of drinking water. This could be more acceptable with an end 

date for grandfathering wells (e.g., - operational before 2012). 

Response: EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and

AoR requirements) should also be grandfathered. Following re-permitting of the project as GS, many

of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

EPA does not plan to institute an "end date" for this requirement since conversion is a site-specific

decision. EPA encourages owners or operators and Directors to coordinate on re-permitted wells to

ensure that all wells used for GS are constructed and operated in a manner that protects USDWs

from endangerment.

Commenter Name: Paul L. Carpinone Letter ID: 0212

Commenter Organization: Tampa Electric Company Comment ID: 22910

Comment: - Given the similarities between Class VI wells (as envisioned by the Proposal) 

and the existing requirements for those Class I and V wells permitted 

exclusively for COz injection, the Final Rule should allow grandfathering of 

construction and operating requirements for these existing wells seeking to 

become Class VI wells provided that it can be demonstrated that such carryingover of requirements will be protective of USDWs. 

Response: EPA agrees that many Class I and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule provides for the construction of

these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to

the Director that the wells were engineered and constructed to meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA

clarifies that only the construction requirements are grandfathered and that all other Class VI

requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met following a

determination under §146.81(c).
Commenter Name: Diane VanDe Hei Letter ID: 0213

Commenter Organization: Association of Metropolitan Water Agencies

(AMWA)

Comment ID:

22940

Comment: - 73 FR 43502 -EPA seeks comment on the approach to grandfather construction 

requirements at the Director’s discretion for existing Class I, Class II, and 

Class V wells seeking to convert to Class VI wells, and whether additional 

construction requirements would be necessary to prevent endangerment to USDWs 

from the GS of CO2. Additionally, EPA seeks comment on how the grandfathering 

approach for existing wells may affect compliance with the requirements in this 

proposal. 

Response: AMWA recommends that any well being considered for injection of CO2 be 

required to meet the same standards as detailed in EPA’s rule for class VI 

wells. For example, the wells must be constructed with the same corrosionresistant materials required under the rule. AMWA is new to the details of the 

UIC program and is concerned that wells constructed under Class I, II and V 

requirements may not have the same protective measures required in EPA’s 

proposed regulation, such as the down-hole shutoff valve. AMWA recommends that 

if EPA proceeds with allowing for wells already constructed to be grandfathered 

and converted to Class VI wells that the owner/operator of the well must 

conclusively demonstrate, through modeling, monitoring and other appropriate 

data, that the well can be operated in compliance with all requirements of the 

final rule. 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

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). EPA clarifies

that only the construction requirements are grandfathered and that all other Class VI requirements

(reporting, monitoring, mechanical integrity testing, etc.) must be met following a determination

under §146.81(c). EPA expects that Directors review and consider many of the factors the

commenter mentions, such as the materials used and the ability of the well to be tested for, and

maintain, mechanical integrity during CO2 injection when making their determination that

§146.81(c) has been met. 

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. However, the Agency

believes that offshore Class VI wells present unique construction and operational conditions,

including isolation from shorelines and the need to construct wells through the water column and the

subsurface, which may delay response time in the event of well difficulties. The rule requires, at

§146.88(e)(3), that owners or operators of offshore wells within State territorial waters install

automatic down-hole shut-off systems. EPA believes that these requirements at §146.88(e) ensure
that proper precautions are taken to prevent subsurface fluid movement and ensure protection of

USDWs.

Commenter Name: Barbara Walz Letter ID: 0216

Commenter Organization: Tri-State Generation and Transmission Association,

Inc.

Comment ID:

22978

Comment: G. Given the similarities between Class VI wells (as envisioned by the proposed 

rule) and the existing requirements for Class I, II, and V wells under the UIC 

program, the final rule should allow grandfathering of construction and 

operating requirements for existing wells seeking to become Class VI wells, 

provided that it is demonstrated that such carrying-over of requirements will be 

protective of USDWs. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

EPA adds that, following re-permitting as Class VI wells, these projects must be subject to the

operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure

requirements in the final GS rule. See the discussion of EPA's final regulatory approach in the

preamble to the GS rule for additional detail on these requirements.

Commenter Name: Darrick Eugene Letter ID: 0223

Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23967

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 3820 2.3.1 Well construction procedures 

Comment: 1. § 146.81 Applicability 

The proposed rule provides that owners or operators of authorized Class I 

industrial, Class II, or Class V experimental CO2 injection projects who seek to 

"convert" these wells to Class VI wells and apply for a Class VI permit may be 

exempted, at the Director’s discretion, from the proposed casing and cementing 

requirements applicable to Class VI wells. 

EPA Proposed § 146.81(c) This subpart applies to owners and operators of 

permit or rule- authorized Class I industrial, Class II, or Class V 

experimental carbon dioxide injection projects who seek to apply for a 

Class VI geologic sequestration permit for their well or wells. If the 

Director determines that USDWs will not be endangered, such wells are 

exempt, at the Director’s discretion, from the casing and cementing 

requirements at §§ 146.86(b) and 146.87(a)(1) through (3). 

It is helpful that EPA recognizes that entities may wish to convert other 

classes of wells (such as Class II wells used for CO2 enhanced oil recovery 

projects) into Class VI wells and that flexibility is necessary for this 
conversion process. This flexibility should be maintained in the final rules but 

should be enhanced. In addition, the rules should be expanded to provide further 

detail on the conversion process. It is critical that owners and operators have 

clear and concise rules to rely on when seeking to grandfather their existing 

wells. This provision should be revised to limit the Director’s discretion and 

address all variances resulting in modifications to existing wells. For 

instance, while the rules waive the Class VI casing and cementing requirements 

for existing wells being converted to Class VI wells, the rules do not address 

other construction or construction-related Class VI well requirements that 

create variances between Class VI and Class I, II and V wells. Those 

requirements include: 

1. Down hole automatic shut-off valve with wellhead hydraulics; 

2. Annulus liquid level detector; 

3. Wellhead corrosion monitoring equipment; and 

4. Mechanical integrity testing. 

Each of these requirements applicable to Class VI wells would require 

retrofitting or modifications to existing wells and could make conversion of 

wells impracticable or excessively expensive. Rather than requiring existing 

wells to meet prescriptive rules that may not be necessary or applicable, the 

decision to grandfather an existing well should be based solely on the well’s 

passing a mechanical integrity test without physical well modification and 

meeting all other Class VI permit requirements that may be met without well 

modification. This change could be accomplished by revising proposed § 146.81(c) 

as follows: 

(c) This subpart applies to owners and operators of permit or rule-authorized 

Class I industrial, Class II, or Class V experimental carbon dioxide injection 

projects who seek to apply for a Class VI geologic sequestration permit for 

their well or wells. If the Director determines that USDWs will not be 

endangered THROUGH THE RESULTS OF MECHANICAL INTEGRITY TESTING PURSUANT

TO § 

146.89 THAT THE WELL IS EFFECTIVE IN PREVENTING ENDANGERMENT OF USDWS,

such 

wells are exempt, at the Director’s discretion, from the casing and 

cementing requirements at §§ 146.86(b) and 146.87(a)(1) through (3) ANY 

REQUIREMENT IMPOSING PHYSICAL WELL MODIFICATIONS, SUBJECT TO MEETING

ALL OTHER 

CLASS VI WELL REQUIREMENTS. 

Response: EPA expects that any decision to convert a well for long term storage of CO2 be made in

the context of all available information about the site and history of injection. The final GS rule

provides for the construction of these wells to be grandfathered per §146.81(c), provided the owner

or operator can demonstrate to the Director that the wells were engineered and constructed to meet

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

§146.86(b) and §146.87(a).

EPA clarifies that other Class VI requirements (i.e., beyond the construction requirements) will not

be grandfathered. Following conversion of the project to Class VI, many of the unique factors of GS
sites (e.g., increased reservoir pressures associated with large volumes of stored CO2 and the

corrosivity of CO2 in the presence of water) warrant the specific operational, MIT, monitoring,

reporting, plugging, post-injection site care, and site closure requirements in the final GS rule.

Therefore, following re-permitting, these projects must be subject to the requirements in the final GS

rule, including requirements related to down-hole shut-off devices, annulus fluid monitoring,

corrosion monitoring, and MITs. EPA adds that only requiring a MIT test for wells converting from

Class I, II, or V would not be sufficient to ensure that the well was adequate to properly contain the

buoyant and corrosive nature of the CO2 stream. EPA believes that down-hole shut-off systems and

corrosion monitoring are also necessary to ensure the well maintains its integrity. See the discussion

of EPA's final regulatory approach in the preamble to the GS rule for additional detail on these

requirements.

If, because of its construction, a current Class II well cannot be converted for GS in such a way that

USDWs are protected from endangerment (i.e., by meeting the monitoring, MIT, and other

requirements for Class VI wells), conversion will not be allowed. While conversion of suitable Class

II wells for GS is desirable in many situations, EPA stresses that protection of USDWs from

endangerment is the primary mission and mandate of the UIC program.

To clarify the point at which the primary purpose of CO2 injection transitions from ER (i.e., a Class

II well) to long-term storage (i.e., Class VI), the final GS rule at §144.19 contains specific, riskbased factors to be considered by the Director in making this determination. Furthermore, EPA is

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

and owner/operators in evaluating where a project may fit within a Class II to Class VI transition.

The guidance describes the methods available for the Director to determine the risk posed to USDWs

from a GS/ER project, and how the Director may determine if a project should be regulated by a

Class II or Class VI UIC program. The guidance will be available on EPA's web site, at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Andrew Duguid Letter ID: 0226

Commenter Organization: Schlumberger Carbon Services Comment ID: 24009

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 146.86) 

Comment: §146.81 Applicability. 

Proposed Rule: (c) This subpart applies to owners and operators of permit or 

rule-authorized Class I industrial, Class II, or Class V experimental carbon 

dioxide injection projects who seek to apply for a Class VI geologic 

sequestration permit for their well or wells. If the Director determines that 

USDWs will not be endangered, such wells are exempt, at the Director’s 

discretion, from the casing and cementing requirements at §§146.86(b) and 

146.87(a)(1) through (3). 

Schlumberger Suggested Revision: (c) This subpart applies to owners and 

operators of permit or rule-authorized Class I industrial, Class II, or Class V 

experimental carbon dioxide injection projects who seek to apply for a Class VI 

geologic sequestration permit for their well or wells. If the Director 

determines that USDWs will not be endangered, such wells are exempt, at the 

Director’s discretion, from the casing and cementing requirements at §§146.86(b) 

and 146.87(a)(1) through (3) if the wells were constructed prior to January 1, 
2010. 

Schlumberger Rationale: We feel that there needs to be a cutoff date for the 

grandfathering of wells so eventually all Class 6 wells are constructed to the 

same standard 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechanical integrity testing, etc.) must be met

following a determination under §146.81(c). 

EPA does not plan to institute a "cut-off date" for this requirement since conversion is a site-specific

decision. EPA believes that the requirement should be based on the specific aspects of the well's

construction, not on the date on which it was constructed.

Commenter Name: Abbie Krebsbach Letter ID: 0235

Commenter Organization: Montana-Dakota Utilities Co. Comment ID: 23190

Comment: Grandfathering Other Wells 

EPA has proposed giving the UIC program discretion to "grandfather" the 

construction requirements for existing Class II and Class V experimental wells 

(as well as existing Class I wells that were not intended to inject CO2 

originally, since well construction requirements for Classes I and proposed VI 

are similar) where the UIC program director can determine that the wells will 

not endanger USDW. Such grandfathering is soundly justified, as these wells have 

been constructed specifically for injection and, particularly in the case of 

Class V experimental wells, for storage of CO2 and are suitable for the purpose 

for which they are designed. The promulgation of new regulations should not 

render them unfit for the purpose for which they were intended. 

Further, permittees of these wells presumably were required to satisfy the nonendangerment standard as part of the initial permitting process. However, under 

these circumstances, potential grandfathering likely would not provide the 

needed assurance, and thus the needed incentives, to project operators or 

investors that existing wells, or, perhaps more importantly, new wells that may 

be permitted before the proposed rules take effect, will remain viable wells 

from a regulatory perspective going forward. 

There is a concern that EOR operators faced with the proposition of 50 or more 

years of financial assurance requirements may decide that the benefits of 

converting to a CCS operation are not worth the costs and could deter CCS 

projects from implementation. It is understood that wells permitted to inject 

and store CO2 have already been deemed safe and suitable for those purposes, and 

a determination has already been made that no endangerment is posed to USDW. 
The grandfathering provision in the rule should be as expansive as possible 

while balancing the need for protection of USDW, and thus Montana-Dakota 

believes that a couple of modifications should be made to the proposed rule. A 

preferable approach would be to expand the scope of available grandfathering for 

existing wells, given that the wells were initially constructed for injection of 

CO2. Also, it would be preferable to allow grandfathering as a default, unless 

the program director determines that, due to specific concerns, a project would 

not be suitable for CO2 storage. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

EPA disagrees with commenters who suggest that the other Class VI requirements (e.g., MITs,

siting, monitoring, operational, financial responsibility, and AoR requirements) should also be

grandfathered. Following re-permitting of the project as GS, many of the unique factors of GS sites

(e.g., increased reservoir pressures associated with large volumes of stored CO2 and the corrosivity

of CO2 in the presence of water) will result in an increased risk profile, warranting the specific

requirements in the final GS rule. Therefore, following re-permitting as Class VI wells, these

projects must be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection

site care and site closure requirements in the final GS rule. See the discussion of EPA's final

regulatory approach in the preamble to the GS rule for additional detail on these requirements.

In response to the comment that ER operators will be discouraged from pursuing GS, EPA clarifies

that this comment is outside the scope of the rule. The purpose of the GS rule is not to incentivize

the use of GS or to address the use of pore space, but to ensure that, where GS is deployed, it is

conducted in a manner that does not endanger USDWs.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23225

Comment: 3. EPA seeks comment on the approach to grandfather construction requirements at 

the Director’s discretion for existing Class I, Class II, and Class V wells 

seeking to convert to Class VI wells, and whether additional construction 

requirements would be necessary to prevent endangerment to USDWs from the GS of 

CO2. EPA Notice 43502. 

If a well has been utilized for injection and is properly constructed under 

existing regulations, it is constructed to prevent the migration of the 

injectate into a USDW. The demonstrated well performance is indicative that 

well construction is protective of USDWs. A review to verify the existing 

construction as protective is sufficient to grandfather the construction as 

protective as a Class VI injection well. 

4. Additionally, EPA seeks comment on how the grandfathering approach for 

existing wells may affect compliance with the other requirements in its 

proposal. EPA Notice 43502. 
See 3 above. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

Following re-permitting of the well as Class VI, these projects must be subject to the operational,

MIT, monitoring, reporting, plugging, and post-injection site care and site closure requirements in

the final GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS

rule for additional detail on these requirements.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23239

Comment: 17. EPA also seeks comment on how the proposed grandfathering provisions for 

existing wells (construction requirements) may affect compliance with the above, 

proposed construction requirements. EPA Notice 43509. 

If a well has been utilized for injection and is properly constructed under 

existing regulations, it is constructed to prevent the migration of the 

injectate into a USDW. The demonstrated well performance is indicative that it 

is protective of USDWs. A review to verify the construction is sufficient to 

grandfather the construction as protective as a Class VI injection well. 

Additional realistic remedial actions short of new construction could be 

required to make the well more protective. 

Response: As described above, EPA agrees that many Class I, Class II, and Class V experimental

technology wells are designed and constructed to withstand exposure to CO2. The final GS rule

provides for the construction of these wells to be grandfathered per §146.81(c), provided the owner

or operator can demonstrate to the Director that the wells were engineered and constructed to meet

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

§146.86(b) and §146.87(a). EPA clarifies that only the construction requirements are grandfathered

and that all other Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.)

must be met following a determination under §146.81(c).

Commenter Name: Walter L. Baker Letter ID: 0253

Commenter Organization: Utah Division of Water Quality Comment ID: 22343

Comment: "GRANDFATHERING" OF EXISTING CO2 INJECTION WELLS 

We support EPA's intent to allow "grandfathering" of the construction 

requirements for existing Class I, II or V wells that are converted to Class VI 

wells. However, conversion to a Class VI well should only be allowed after an 

assessment of the geochemical interaction between the CO2, previous injectate, 

injection zone matrix and fluid indicates there will be no deleterious effects 

due to the commingling of different injection streams that might compromise the 
CCGS project or endanger USDWs. This is especially relevant when converting 

Class I and Class V wells to Class VI wells. 

Response: EPA agrees and expects that any decision to convert a well for long term storage of CO2

will be made in the context of all available information about the site and history of injection. EPA

agrees that many Class I, Class II, and Class V experimental technology wells are designed and

constructed to withstand exposure to CO2. The final GS rule provides for the construction of these

wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the

Director that the wells were engineered and constructed to meet the requirements at §146.86(a) and

ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

Following re-permitting of the well as Class VI, the project must be subject to the siting, operational,

MIT, monitoring, reporting, plugging, and post-injection site care and site closure requirements in

the final GS rule. This would most likely include an evaluation of the properties of the rock in the

injection zone and fluid composition in the context of the proposed CO2 injection, as the commenter

suggests. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for

additional detail on these requirements.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24853

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: EPA Proposal: (c) This subpart applies to owners and operators of permit or 

rule-authorized Class I industrial, Class II, or Class V experimental carbon 

dioxide injection projects who seek to apply for a Class VI geologic 

sequestration permit for their well or wells. If the Director determines that 

USDWs will not be endangered, such wells are exempt, at the Director’s 

discretion, from the casing and cementing requirements at §§ 146.86(b) and 

146.87(a)(1) through (3). 

GWPC Recommendations: (c) This subpart applies to owners and operators of permit 

or rule-authorized Class I industrial, Class II, or Class V experimental carbon 

dioxide injection projects who seek to apply for a Class VI geologic 

sequestration permit for their well or wells or to convert to Class II GS 

operation. If the Director determines that USDWs will not be endangered, such 

wells are exempt, at the Director’s discretion, from such Class VI requirements 

contained in this subpart as the Director specifies. 

Rationale: The proposed EPA waiver applies only to the casing and cementing 

requirements. Directors should have the flexibility to waive other requirements 

as appropriate for conversions to Class VI. 

Response: EPA disagrees with commenters who suggest that other requirements (outside of well

construction) should also be grandfathered. Following re-permitting of the project as GS, many of

the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the
discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements. 

Commenter Name: Claire Olson Letter ID: 0260

Commenter Organization: Basin Electric Power Cooperative Comment ID: 22389

Comment: "G. How Would This Proposal Affect Existing Injection Wells Under the UIC Program?

" 

EPA's approach to CO2 injection in Class II and Class V wells for EOR/EGR as 

long as oil/gas production continues does not take into consideration the GS of 

CO2 that takes place from this process. CO2, at the time of injection in Class II 

and Class V wells for EOR/EGR, needs to be considered sequestered and in GS 

until production from the field is completed. Upon completion of the field, 

Class II and Class V wells will be issued a GS permit and the construction 

requirements needs to be grandfathered into the Class VI well classification. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

Following re-permitting as Class VI wells, these projects must be subject to the operational, MIT,

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final

GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for

additional detail on these requirements.

Letter ID: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22791

Comment: II . G. How Would This Proposal Affect Existing Injection Wells Under the UIC

Program? 

C. EPA is proposing to give the Director discretion to carry over or 

"grandfather" the construction requirements (e.g., permanent, cemented well 

components) for existing Class I and Class II wells seeking a permit for GS of CO2, 

provided he/she is able to make a determination that these wells would not 

endanger USDWs. 

IOGCC Response: The IOGCC agrees that discretion is appropriate and necessary 

when reviewing other UIC class wells for use as UIC Class VI wells or another 

class of well as suggested in the response to II.G(B) above. 

II . G. How Would This Proposal Affect Existing Injection Wells Under the UIC Program? 

D. Accordingly, EPA is proposing that the Director have the discretion to 

"grandfather" the construction requirements for Class Experimental wells when 

they are converted to full-scale GS Class VI wells. As with converted Class I 
and Class II wells, these grandfathered wells would be required to meet the 

other requirements of today's proposed rule (e.g., operating, monitoring, MIT, 

well plugging, post-injection site care and site closure). 

IOGCC Response: The IOGCC agrees that discretion is appropriate and necessary 

when reviewing other UIC class wells for use as UIC Class VI wells or another 

class of well as suggested in the response to II. G(B) above. 

11. G. How Would This Proposal Affect Existing Injection Wells Under the UIC Program? 

E. EPA seeks comment on the approach to grandfather construction requirements at 

the Director's discretion for existing Class I, Class II, and Class V wells 

seeking to convert to Class VI wells, and whether additional construction 

requirements would be necessary to prevent endangerment to USDWs from the GS 

of CO2. 

IOGCC Response: As part of the primacy package negotiated with the state, when an 

operator submits an application to reclassify any existing injection well to Class 

VI or other storage well classification, the Director should have the 

flexibility to determine whether the well meets the federal Class VI or another 

storage well classification which incorporates protective standards and requires 

the operator to adhere to the permitting process. 

II. G. How Would This Proposal Affect Existing Injection Wells Under the UIC Program? 

F. Additionally, EPA seeks comment on how the grandfathering approach for 

existing wells may affect compliance with the requirements in this proposal. 

IOGCC Response: As part of the primacy package negotiated with the state, when an 

operator submits an application to reclassify any existing injection well to Class 

VI or other storage well classification, the Director should have the flexibility 

to determine whether the well meets the federal Class VI or another storage well 

classification which incorporates protective standards and requires the operator 

to adhere to the permitting process. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c). 

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

assist Directors in evaluating when and 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 CO2. The guidance describes recommended methods for the Director to

evaluate when determining 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.

Letter ID: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22803

Comment: III A. 3 Proposed Injection Well Construction Requirements 

R. EPA also seeks comment on how the proposed grandfathering provisions for 

existing wells (construction requirements) may affect compliance with the above, 

proposed construction requirements. 

IOGCC Response: The IOGCC believes that Director discretion is appropriate and 

necessary when reviewing other UIC Class wells for use as UIC Class VI wells. 

Overly prescriptive well construction requirements will limit the use of existing 

UIC wells and possible sequestration zones. 

Response: As described above, EPA agrees that many Class I, Class II, and Class V experimental

technology wells are designed and constructed to withstand exposure to CO2. The final GS rule

provides for the construction of these wells to be grandfathered per §146.81(c), provided the owner

or operator can demonstrate to the Director that the wells were engineered and constructed to meet

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

§146.86(b) and §146.87(a).

Commenter Name: Steven Chester Letter ID: 0264

Commenter Organization: Michigan Department of Environmental Quality

(MDEQ)

Comment ID:

22833

Comment: EPA (II. G.) proposes that the Director have discretion to carry over or 

"grandfather" the construction requirements for existing Class I, II, and V wells 

when they are converted to GS wells. 

- Staff believes that, before allowing the wells to be "grandfathered," 

the existing well construction must be evaluated with respect to potential 

migration of injected CO2 upward via the well bore and remedial action required 

if the existing construction does not conform with construction requirements for 

new GS wells. 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased
reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final Class VI rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

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). This

demonstration must address the potential for upward migration of injected CO2. 

EPA adds that, following re-permitting as Class VI wells, these projects must be subject to the MIT

requirements in the final GS rule. See the discussion of EPA's final regulatory approach in the

preamble to the GS rule for additional detail on these requirements.

Commenter Name: Michael Moore Letter ID: 0265

Commenter Organization: North American Carbon Capture & Storage

Association (NACCSA)

Comment ID:

22856

Comment: - Grandfathering Provisions: The Agency should (1) expand the scope of 

available grandfathering beyond construction requirements and (2) allow 

grandfathering unless an examination of specified factors reveals that the 

project would be unsuitable for CO2 storage. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

EPA disagrees that other requirements should also be grandfathered or that grandfathering should be

considered the "default" for all wells seeking conversion to Class VI. Following re-permitting of the

project as GS, many of the unique factors of GS sites (e.g., increased reservoir pressures associated

with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water) will result in

an increased risk profile, warranting the specific requirements in the final GS rule. Therefore,

following re-permitting as Class VI wells, these projects must be subject to the operational, MIT,

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final

GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for

additional detail on these requirements.

Commenter Name: Michael Moore Letter ID: 0265

Commenter Organization: North American Carbon Capture & Storage

Association (NACCSA)

Comment ID:

22870

Comment: 7. Grandfathering Provisions 

As referenced above, EPA has also raised for consideration how certain existing 

wells should be addressed under the final regulations. In particular, EPA has 

proposed allowing the UIC program director to "grandfather," on a discretionary 

basis, the construction requirements for existing Class II and Class V 

experimental wells (as well as existing Class I wells that were not intended to 

inject CO2 originally) where the director can determine that the wells will not 
endanger underground sources of drinking water. But the proposed grandfathering 

is not merely discretionary; it is also limited in scope to construction 

requirements. Thus, operators would be required to satisfy all other provisions 

of the Class VI permitting requirements in order to transition to Class VI wells. 

The limited scope of the grandfathering provision may make it hard for other 

classes of wells to transition to Class VI. 

The proposed provision provides little assurance to project operators or 

investors that existing wells, or wells that may be permitted before the 

proposed rule takes effect, could ever be transitioned to the Class VI regime. 

In light of the additional proposed limitations on GS projects, such as the 

restrictions on receiving formations, grandfathering may simply prove 

impossible, even for projects that were specifically designed to inject and 

store CO2 in the first instance. 

Further, as noted above, wells permitted to inject and store CO2 have already 

been deemed safe and suitable for those purposes, and a determination has already 

been made that no endangerment is posed to USDWs. Under these circumstances, 

leaving a grandfathering determination to the discretion of the directordiscretion that may be exercised where the director determines that there is no 

endangerment to USDWs-is unnecessarily duplicative as long as the operating 

parameters of the site are unchanged. 

NACCSA thus recommends that the Agency expand the scope of available grandfathering 

for existing wells beyond construction requirements to cover all Class VI 

requirements. Further, rather than leave grandfathering to the discretion of the 

program director, a preferable approach would be to allow grandfathering unless, 

upon an examination of specified criteria, the director determines that the 

circumstances of the initial project, as compared to the long-term storage 

aspect, result in a project that is unsuitable for CO2 storage from a point 

of view of protecting USDWs. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

EPA disagrees that the other Class VI requirements (e.g., MITs, siting, monitoring, operational, and

AoR requirements) should also be grandfathered. Following re-permitting of the well as Class VI,

many of the unique factors of GS sites (e.g., increased reservoir pressures associated with large

volumes of stored CO2 and the corrosivity of CO2 in the presence of water) will result in an

increased risk profile, warranting the specific requirements in the final Class VI rule. Therefore,

following re-permitting as Class VI wells, these projects must be subject to the operational, MIT,

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final

GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for

additional detail on these requirements.

EPA clarifies that the purpose of the GS rule is not to incentivize the use of GS or to address the use
of pore space. The purpose of the GS rule is to ensure that, where GS is deployed, it is conducted in

a manner that does not endanger USDWs.

Commenter Name: William Herz Letter ID: 0266

Commenter Organization: The Fertilizer Institute Comment ID: 22877

Comment: Reclassification of Existing Wells as Class VI Wells 

EPA seeks comment on its approach to grandfather construction requirements at 

the Director's discretion for existing Class I, Class II, and Class V wells 

seeking to convert to Class VI wells, and whether additional construction 

requirements would be necessary to prevent endangerment to USDWs from the GS of CO2. 

Additionally, EPA seeks comment on how the grandfathering approach for existing 

wells may affect compliance with the requirements in this proposal (73 Fed. Reg. 

43,502). 

TFI also supports provisions allowing Class I, II and V wells to be repermitted as 

Class VI wells. We also support proposed language that would "grandfather" 

construction requirements for Class I or II wells seeking repermitting as a Class 

VI well. TFI does not foresee the need for additional construction requirements 

or that grandfathering existing Class I, Class II, and Class V wells will affect 

compliance with the proposed Class VI regulations. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

Commenter Name: Bill Hertz Letter ID: 0500

Commenter Organization: Fertilizer Institute Comment ID: 21209

Comment: We also support provisions allowing Class I, II, and V to be re-permitted as 

Class VI wells. We support proposed language that would grandfather construction 

requirements for Class I or II wells seeking re-permitting as a Class VI Well. 

We agree that other abandoned mines, including potentially potash mines are 

potential CO2 storage options and would be willing to assist the EPA in 

exploring this matter further. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c).

Commenter Name: Mark Singer Letter ID: 0504
Commenter Organization: Green America Project, LLC Comment ID: 21246

Comment: I'd like to comment on the grandfathering issue in the proposal. The EPA 

proposes to give the director discretion to grandfather construction 

requirements for Class I, II, and V wells seeking to convert to geologic 

sequestration as Class VI. This makes no sense as well. 

The construction requirements are there for a reason. The question must be 

whether the existing wells satisfy the structural criteria, that is the, the 

requirements for integrity of a Class VI well. So rather than grandfather, the 

rule should be that existing wells must show that they satisfy the functional 

requirements of Class VI construction. 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies that only

the construction requirements are grandfathered and that all other Class VI requirements (reporting,

monitoring, mechnical integrity testing, etc.) must be met following a determination under

§146.81(c). 

EPA adds that conversion of the well will be at the Director's discretion following an evaluation of

all other site-specific information about the well and the project, e.g., modeling, monitoring, and

other data. EPA believes that this addresses the suggestion that the wells satisfy the functional

requirements of Class VI construction.

Commenter Name: Lee Sprague Letter ID: 0505

Commenter Organization: Sierra Club Comment ID: 21237

Comment: I don't think that any grandfathering of existing class, existing classes of 

wells should be allowed to, under the UIC for CO2 sequestration. They should be 

required to fulfill all of the requirements, including some of the public 

participation and review requirements that I've outlined initially. And I am 

still collecting more information, and I will provide that. 

Response: EPA disagrees that grandfathering of construction requirements should not be allowed in

the final GS rule. However, EPA agrees that a cautious approach to grandfathering is appropriate,

particularly given that the converted well will be used for a substantially different process, which

involves increased reservoir pressures associated with large volumes of stored CO2 and the

corrosivity of CO2 in the presence of water. The final GS rule provides for the construction of these

wells to be grandfathered (per 146.81(c)). EPA has included a requirement in the final GS rule that

owners or operators seeking to convert existing wells for long term storage must demonstrate to the

Director that the grandfathered wells were engineered and constructed meet the requirements at

§146.86(a) and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA adds that, following re-permitting as Class VI wells, these projects would be subject to the

operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure
requirements in the final GS rule. Furthermore, all grandfathered wells that are converted to Class VI

will be subject to the same public notice and comment procedures as a new Class VI well.

See the discussion of EPA's final regulatory approach in the preamble to the GS rule for additional

detail on these requirements.

Commenter Name: Kevin Frederick Letter ID: 0525

Commenter Organization: Wyoming Department of Environmental Quality Comment ID: 21398

Comment: There are areas that we agree with EPA that discretion allowed to the director 

should be provided to determine or require grandfathering the construction 

requirements for existing Class I and Class II wells and Class V wells seeking a 

permit for geologic sequestration of CO2. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c). 

EPA adds that conversion of the well must be at the Director's discretion following an evaluation of

all other site-specific information about the well and the project, e.g., modeling, monitoring, and

other data.

Commenter Name: Doug Louis Letter ID: 0530

Commenter Organization: Kansas Corporation Commission Comment ID: 21333

Comment: For states that will have existing rules specifically, what will happen to 

projects that are permitted as classified, experimental wells after the EPA 

passes its rule, but before the states adopt EPA's rules? 

Another concept that needs to be fully discussed is full-scale, not experimental 

injection facilities that are applied for before proposed EPA rules are adopted? 

How will they be permitted, that is what class would they be, and who would 

permit them? The proposed rule should address these specific scenarios. 

Response: EPA clarifies that GS experimental research projects will continue to be regulated as

Class V experimental technology wells as long as they remain of an experimental nature. EPA adds

that within one year of issuance of the GS rule, projects that are non-experimental must be repermitted as Class VI wells and be subject to the requirements of the GS rule. GS projects that

continue to be of an experimental nature may continue to be permitted as Class V experimental

technology wells.

Commenter Name: Doug Louis Letter ID: 0530

Commenter Organization: Kansas Corporation Commission Comment ID: 21334

Comment: Concerning grand-fathering Class II wells to Class VI wells. It is believed a 

great deal of potential storage CO2 exists in CO2 floods after oil production 
ceases. It is my concern that EPA's stringent standards for well construction 

monitoring and financial assurance will discourage well operators from using 

this additional pore space for sequestration thus causing waste. If a CO2 

recovery operation has successfully operated for many years, why should the 

standards be raised simply because it undergoes a well classification change? 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c). 

In response to the comment that ER operators will be discouraged from pursuing GS or using

additional pore space for storage, EPA clarifies that this comment is outside the scope of the GS

rulemaking. The purpose of the GS rule is not to incentivize the use of GS or to address the use of

pore space, but to ensure that, where GS is deployed, it is conducted in a manner that does not

endanger USDWs.

Commenter Name: Mike Moore Letter ID: 0532

Commenter Organization: North American Carbon Capture and Storage

Association (NACCSA)

Comment ID:

21371

Comment: The fifth area relates to the proposed rule's grandfathering of existing wells. 

Under the proposed rule, if a Class II or V well operator wishes to transition 

to Class VI well, the operator would be required to meet new Class VI 

requirements. This discourages early deployment of CCS because operators will 

face potentially significant new obligations. The rules should broadly permit 

grandfathering unless the director determines that a particular site is not 

suitable for storage based on specific criteria. The rule also unnecessarily 

creates a dichotomy between Class II wells and Class VI wells. Class II is only 

available as long as any production is occurring. This may prevent EOR wells 

from being transitioned to permanent storage after EOR ceases or ends. EPA's 

rules should grant carbon dioxide storage the same legal status under all well 

classes. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides the the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c). 

In response to the comment that ER operators will be discouraged from pursuing GS or using

additional pore space for storage, EPA clarifies that the comment is outside the scope of this

rulemaking. The purpose of the GS rule is not to incentivize the use of GS or to address the use of
pore space, but to ensure that, where GS is deployed, it is conducted in a manner that does not

endanger USDWs.

Comment Code: 2062 1.5.3.1 Grandfathering construction of Class I wells (seeking comment) 

Individual Comments

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24758

Other EPA Comment Codes and Descriptions: 2060 1.5.3 Comments on grandfathering of

existing wells (seeking comment); 2064 1.5.3.2 Grandfathering construction of Class II wells

(seeking comment); 2066 1.5.3.3 Grandfathering construction of Class V wells (seeking comment) 

Comment: Subpart H--Criteria and Standards Applicable to Class VI Wells 

§146.81 Applicability. 

(a) This subpart establishes criteria and standards for UIC programs to regulate 

Class VI CO2 GS injection wells. (b) This subpart applies to wells used to 

inject CO2 specifically for the purpose of GS, i.e., the long-term containment 

of a gaseous, liquid or supercritical CO2 stream in subsurface geologic 

formations. (c) This subpart applies to owners and operators of permit or ruleauthorized Class I industrial, Class II, or Class V experimental CO2 injection 

projects who seek to apply for a Class VI geologic sequestration permit for 

their well or wells. If the Director determines that USDWs will not be 

endangered, such wells are exempt, at the Director's discretion, from the casing 

and cementing requirements at §§146.86(b) and 146.87(a)(1) through (3). 

{RRC agrees that the Director evaluating a permit application to use existing 

injection wells for geologic sequestration should have the discretion to exempt 

wells from Class I industrial, Class II or Class V wells from the proposed 

casing and cementing requirements of Class VI wells. } 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c).

Commenter Name: James Rower Letter ID: 0173

Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23477

Other EPA Comment Codes and Descriptions: 2066 1.5.3.3 Grandfathering construction of Class

V wells (seeking comment) 

Comment: 4. Grandfathering Requirements for Class I and V UIC Wells 
Grandfathering is an extremely important issue to USWAG as a number of our 

members have invested substantial resources in developing and permitting 

nonhazardous Class I and V experimental CO2 injection wells to help demonstrate 

the viability of large-scale commercial deployment of CO2 sequestration. Federal 

and state governments are encouraging these efforts as their success is critical 

to the large-scale commercial deployment of CO2 sequestration. Therefore, Owners 

or Operators should be given the opportunity to operate these wells on a regular 

basis as Class VI wells once the wells have been shown to be safe and effective 

on an experimental basis. This will help encourage the substantial upfront 

investment necessary to get these wells permitted. USWAG therefore supports the 

Proposal's provision allowing for the grandfathering of construction 

requirements for existing Class I and V wells developed for the injection of CO2 

if and when Owners or Operators of those wells seek a Class VI permit for GS of 

CO2. Id. at 43502. 

Response: EPA agrees that many Class I and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule provides for the construction of

these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to

the Director that the wells were engineered and constructed to meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA

clarifies that only the construction requirements are grandfathered and that all other Class VI

requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met following a

determination under §146.81(c).

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25173

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: C. EPA is proposing to give the Director discretion to carry over or 

"grandfather" the construction requirements (e.g., permanent, cemented well 

components) for existing Class I and Class II wells seeking a permit for GS of 

CO2, provided he/she is able to make a determination that these wells would not 

endanger USDWs. 

NYSDEC-DMN Response: NYSDEC-DMN agrees that this discretion is appropriate and 

necessary when reviewing other UIC Class wells for use as UIC Class VI wells. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c).

Commenter Name: Philip Papadeas Letter ID: 0238
Commenter Organization: Sandia Technologies, LLC Comment ID: 23346

Comment: Well Conversion 

An operator can potentially use a Class I permit to inject CO2, H2S, and NO2 and 

utilize an established program which is considered more stringent and successful 

to not endanger USDWs or the public. 

For Class I well operators who might want to convert an abandoned injection well 

to a Class VI well, should have an easier path to such due to the more stringent 

permit and diligence performed to obtain regulatory approval and permits. 

Historical operations have not endangered USDWs, therefore there is a direct 

connection to a ‘grandfather’ approach. 

Response: EPA agrees that many Class I wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a). However, EPA clarifies that only the

construction requirements are grandfathered and that all other Class VI requirements (reporting,

monitoring, mechnical integrity testing, etc.) must be met following a determination under

§146.81(c).

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

Individual Comments

Commenter Name: Matt Toner Letter ID: 0117

Commenter Organization: Hydrogen Energy International Comment ID: 22058

Comment: EPA has recognized the valuable role that oil and gas reservoirs can play in the 

geologic storage of CO2, and Hydrogen Energy would encourage that EPA go 

significantly further in facilitating use of these reservoirs. When CO2 is 

injected for Enhanced Oil or Gas Recovery, it could at the same time be 

sequestered for long term storage at the option of the operator. EPA should 

recognize this concurrent dual purpose, CO2 Injection for Enhanced Oil or Gas 

Recovery and Designed Storage, and allow this dual purpose under existing Class 

II UIC rules. Furthermore, EPA regulations should Hydrogen Energy International 

Comments to EPA Proposed Rule facilitate grandfathering from dual purpose 

production and storage to storage-only sites when EOR/EGR operations are 

completed. 

In the course of a typical EOR operation, even where there is no intent to 

sequester, 30-50% on the injected CO2 remains in the reservoir after production 

operations cease. The balance is either miscibly dissolved within the produced 

oil or recycled for use in other reservoirs - it is not emitted to the 

atmosphere. Today ~90% of the CO2 used in enhanced recovery operations is 

produced from naturally occurring accumulations. Rather than using this 

naturally occurring CO2, society can mitigate greenhouse gas emissions by using 
anthropogenic sources. In addition, injection can continue upon the completion 

of production operations, to fully utilize all existing pore space - What we 

call EOR + Storage. 

Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies that only the construction

requirements are grandfathered and that all other Class VI requirements (reporting, monitoring,

mechnical integrity testing, etc.) must be met following a determination under §146.81(c).

Commenter Name: Matt Toner Letter ID: 0117

Commenter Organization: Hydrogen Energy International Comment ID: 22061

Other EPA Comment Codes and Descriptions: 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: STREAMLINING OF REQUIREMENTS 

Existing Class II regulations governing injection of CO2 in oil & gas reservoirs 

have proven successful at protecting USDWs and the health and safety of the 

public at large. These regulations should allow for the dual purpose of 

sequestration, if anthropogenic CO2 is used. 

Hydrogen Energy also recommends that EPA expand grandfathering to facilitate transition from

production and storage to storage-only sites, which will incentivize the use of these reservoirs for

long-term CO2 storage. 

Proposed grandfathering of Class II wells should go beyond just construction 

requirements to include, at a minimum, operating and mechanical integrity 

requirements for existing, operationally compliant, Class II EOR-CO2 injection 

wells. The Class VI requirements would require technically unnecessary changes 

to equipment and monitoring procedures. 

Some authors have identified leakage risk with using oil & gas reservoirs for 

CO2 sequestration due to the presence of inactive wells. Proper plugging and 

abandonment of inactive wells is a proven method which can ensure this risk is 

effectively managed. In addition, the oil and gas industry has developed 

techniques to quickly isolate, effectively repair and remediate these issues, in 

their unlikely occurrence. 

Response: As described above, the final GS rule provides for the construction of Class II wells to be

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

the wells were engineered and constructed to meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the well as Class VI, many

of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,
plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

Commenter Name: Matt Toner Letter ID: 0117

Commenter Organization: Hydrogen Energy International Comment ID: 22062

Other EPA Comment Codes and Descriptions: 2044 1.5.2.2 Oppose Class VI/ Support Class II 

Comment: In closing, Hydrogen Energy would like to applaud EPA for their effort to create 

an effective regulatory framework for the sequestration of Carbon Dioxide while 

protecting USDW's. However, we believes that EPA should go significantly further 

than the proposed regulation, by recognizing the potential for concurrent, CO2 

Injection for Enhanced Oil or Gas Recovery and Designed Storage and allowing for 

this dual purpose. Furthermore, EPA should facilitate grandfathering from dual 

purpose production and storage to storage-only sites when EOR/EGR operations are 

completed. 

Response: EPA clarifies that injection for enhanced recovery is permitted under Class II. EPA

disagrees that dual purpose underground injection should be authorized under the UIC program

because the unique risks posed by long term storage of CO2 for GS cannot be addressed under

existing UIC requirements, such as those for Class II wells. EPA believes that there are significant

differences between how projects are operated, as well as the risks posed by these different injection

activities. The new tailored approach of the GS rule was designed to address the general risks deep

injection may pose to USDWs and was tailored specifically to address the risks posed by long term

storage of CO2 (i.e., very large volumes, very long time-periods, and reservoir pressure conditions).

EPA notes that many Class II wells are designed and constructed to withstand exposure to CO2. 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 sitespecific flexibility. For more information, please see the discussion on transition of Class II wells in

the preamble to the final GS rule.

Commenter Name: Doug Louis Letter ID: 0121

Commenter Organization: Kansas Corporation Commission Comment ID: 22074

Other EPA Comment Codes and Descriptions: 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: Grandfathering Class II wells to Class VI wells. 

It is believed a great deal of potential storage of CO2 exists in EOR-CO2 floods 

after oil production ceases. It is my concern that EPA’s stringent standards for 

well cementing, monitoring and financial assurance will discourage oil operators 

using this additional pore space for sequestration, thus causing waste. If a 

CO2-EOR operation has successfully operated for many years, why should the 
standards be raised simply because it undergoes a well classification change? 

Response: Underground injection for the primary purpose of long term storage is sufficiently

different from Class II ER operations and warrants tailored requirements provided in the GS

rulemaking. For example, the volume of CO2 anticipated to be injected in Class VI wells is

significantly greater than for Class II wells. Reservoir pressure conditions will also be different, with

Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II ER projects. 

In response to the comment that ER operators will be discouraged from pursuing GS or using

additional pore space for storage, EPA clarifies that the purpose of the GS rule is not to incentivize

or encourage the use of GS or to address the use of pore space. The purpose of the GS rule is to

ensure that, where GS is deployed, it is conducted in a manner that does not endanger USDWs.

Furthermore, based on the administrative record, which includes the evaluation of available project

data, EPA believes that the Class VI requirements are not overly stringent and reflect the operation,

monitoring, and modeling currently conducted at several existing GS sites

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24758

Other EPA Comment Codes and Descriptions: 2060 1.5.3 Comments on grandfathering of

existing wells (seeking comment); 2062 1.5.3.1 Grandfathering construction of Class I wells (seeking

comment); 2066 1.5.3.3 Grandfathering construction of Class V wells (seeking comment) 

Comment: Subpart H--Criteria and Standards Applicable to Class VI Wells 

§146.81 Applicability. 

(a) This subpart establishes criteria and standards for UIC programs to regulate 

Class VI CO2 GS injection wells. (b) This subpart applies to wells used to 

inject CO2 specifically for the purpose of GS, i.e., the long-term containment 

of a gaseous, liquid or supercritical CO2 stream in subsurface geologic 

formations. (c) This subpart applies to owners and operators of permit or ruleauthorized Class I industrial, Class II, or Class V experimental CO2 injection 

projects who seek to apply for a Class VI geologic sequestration permit for 

their well or wells. If the Director determines that USDWs will not be 

endangered, such wells are exempt, at the Director's discretion, from the casing 

and cementing requirements at §§146.86(b) and 146.87(a)(1) through (3). 

{RRC agrees that the Director evaluating a permit application to use existing 

injection wells for geologic sequestration should have the discretion to exempt 

wells from Class I industrial, Class II or Class V wells from the proposed 

casing and cementing requirements of Class VI wells. } 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met
following a determination under §146.81(c).

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141

Commenter Organization: Global Energy, Inc. Comment ID: 23102

Other EPA Comment Codes and Descriptions: 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: 3.We highly recommend that EPA think in terms of the 80-20 rule of pragmatism 

when determining how to implement the conversion of an EOR well to a 

sequestration well. It is arguable that an EOR well is sufficiently relevant 

to a Class-6 well and has sufficient integrity to give it credit (at least 

partial credit) in the carbon injection and storage calculus. Reasonable 

mechanical retrofits may be appropriate, without having to replace casing, for 

example. 

In this we strongly support the EPA suggestion that EOR wells might be 

grandfathered when considering conversion to a GS well. Reasonable rework, 

though not reinstallation (or re- cementing, for example) might be decided on a 

case-by-case basis. That is, a single well, or a few wells, are not likely to 

materially affect USDW. 

Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a).

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 adds that, following re-permitting as Class VI wells, these

projects must be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection

site care and site closure requirements in the final GS rule.

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

assist Directors in evaluating 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 when determining 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.

Commenter Name: Christine Reimer Letter ID: 0142
Commenter Organization: National Ground Water Association Comment ID: 22544

Other EPA Comment Codes and Descriptions: 2066 1.5.3.3 Grandfathering construction of Class

V wells (seeking comment) 

Comment: Classification of Injection Wells for Carbon Sequestration, Class II Injection 

Well Transition, and Grandfathering 

The EPA published a guidance document in March of 2007 recommending that the 

geologic sequestration experimental projects during this period of research use 

the Class V experimental category for classification of the injection wells 

(Using the Class V Experimental Technology Well Classification for Pilot 

Geologic Sequestration Projects - EPA 2007). These projects are currently 

underway at the Department of Energy’s (DOE’s) National Energy Technology 

Laboratory Regional Partnership test sites. Thus, there will be a need in the 

future for a regulatory mechanism for transition of these Class V experimental 

wells to Class VI operational status. There are also a number of Class II 

enhanced oil recovery (EOR) wells that have been used for testing of the 

sequestration process. These wells, too, may need a mechanism for transition to 

Class VI for operational use. 

Response: EPA agrees that many Class II and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule provides for the construction of

these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to

the Director that the wells were engineered and constructed to meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA does not believe that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the well as Class VI, many

of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22545

Other EPA Comment Codes and Descriptions: 2066 1.5.3.3 Grandfathering construction of Class

V wells (seeking comment); 3130 2.1.3 Comments that operators should submit more (or different)

geologic data than proposed; 4710 2.7.1 Proposed submissions required for permit applications

(seeking comment) 

Comment: The NGWA Carbon Sequestration Task Force recommends that the experimental phase 

extend beyond the regional partnerships to each site proposed for productionscale injection of carbon dioxide. It is recommended that at least one well at 

each site be constructed under the Class V experimental category, and that 

testing of the adequacy of the geologic environment for geologic sequestration 

of carbon dioxide be conducted prior to permitting any well in the Class VI 

category at the site. 
The transition of carbon dioxide injection wells from Class II (Enhanced Oil 

Recovery wells) to Class VI (carbon sequestration wells) will presumably be 

requested when production of the petroleum has ceased. Liquid carbon dioxide 

from a distant source, such as a power plant, can be stored in the depleted 

petroleum reservoir even after production has ceased, necessitating a change in 

classification of the injection well. The new use of the wells involves much 

longer storage time, and raises concerns about mechanical integrity and long 

term effects, including geochemical changes, on underground source of drinking 

water (USDWs). The reclassification should depend on a positive outcome from a 

Class V experimental program conducted in the depleted reservoir, as described 

below. 

The "grandfathering" of Class V carbon sequestration wells would mean allowing 

experimental wells to be permitted for operation after the testing period is 

over. The NGWA Carbon Sequestration Task Force recommends that each carbon 

sequestration system or wellfield have an experimental phase, and not rely on 

results from distant experimental locations. Thus, nearly every operational 

well would start as a Class V experimental well, or would go through a Class VI 

testing phase, before being permitted for long-term operation. The transition 

to Class VI operational status would require demonstrating that the minimum 

requirements are met at that location. Most wells would go through the 

following permitting phases: 

- Class V experimental well construction permit: This permit would allow 

geologic and geophysical testing, aquifer testing, laboratory work, etc, but 

would not include injection of CO2 (only potable water injection testing would 

be allowed). 

- Class VI experimental well operational testing permit: At this stage, 

the full monitoring facilities would need to be constructed. This permit would 

allow test injection of liquid CO2 at rates high enough to demonstrate that the 

location meets the minimum requirements for operation, for a period of up to two 

years. 

- Class VI operation permit: After demonstrating that the location and 

the well meet all the minimum requirements for injection of CO2, the operation 

permit can be issued. 

The goals of the experimental well Class V construction permit would be to make 

the following demonstrations: 

- A receiving zone of sufficient depth, area extent, thickness, porosity, and 

permeability is present; 

- Lithologic description, geological name, thickness and depth of each confining 

unit above the storage aquifer, and of each USDW. 

- A trapping mechanism that is free of pathways for migration of injected fluids 

into a USDW. These pathways may include major non-sealing faults, porous beds 

within the confining unit, changes of facies trending toward more porous units 
and man-made structures such as wells or mine shafts. A trapping mechanism is 

defined as a geologic environment that prevents vertical and horizontal movement 

of fluids into a USDW; The volume of the trap shall exceed the proposed total 

volume of injected carbon dioxide for the life of the proposed facility 

- Identification of all confining units between the primary injection/storage 

zone and the lowermost USDW, and their adequacy to contain the injected fluid. 

Unless the only feasible injection zone has only one confining unit separating 

it from the lowermost USDW, this demonstration includes adequacy of confinement 

for both the primary confining unit and a secondary containment system that 

extends to the base of the lowermost USDW and is completely redundant of the 

primary confining system and could confine the injected CO2 should the primary 

system fail. In locations where the secondary containment system is not 

possible, the applicant shall propose an alternative system of early warning of 

failure of the primary confining unit in order to avoid impacting any USDW 

should that confinement fail. This demonstration applies in the horizontal 

sense as well, demonstrating one or more mechanisms containing the fluid from 

horizontal movement into a USDW in the storage aquifer at a distant location. 

- The construction of an operational monitoring system meeting all the 

requirements described in this document’s MMV section, and demonstration of the 

adequacy of this system to meet those requirements. 

- Demonstration of mechanical integrity 

Having made the foregoing demonstrations, a Class VI operational testing permit 

can be issued for a period of up to two years. The goals of the experimental 

well Class VI operational testing permit would be to make the following 

demonstrations: 

- A hydraulic demonstration of the adequacy (depth, area extent, thickness, 

porosity, and permeability) of the storage zone, using monitoring data and 4-D 

seismic monitoring of the extent of the CO2 plume. 

- Demonstration of the adequacy of the trap for 5/10 years of injection at the 

proposed rate. The volume of the trap shall exceed the proposed total volume of 

injected carbon dioxide for the 5/10 years of the first operation permit. 

- Demonstration of the adequacy of confinement under operational conditions 

using monitoring data and a method of detecting the extent of the CO2 plume in 

the storage aquifer, such as 4-D seismic monitoring or direct sampling. 

- Re- evaluation of the Area of Review and extent of the zone of endangering 

influence. 

- Re-evaluation of mechanical integrity, using the buoyancy of the injected CO2 

to better measure external mechanical integrity. The re-evaluation shall 

include the testing required during the initial MIT, as well as evaluation of 

the cement for carbonation, or chemical weathering by CO2 

Under this permitting scenario, the vast majority of Class V experimental wells 

would be constructed after the Class VI standards had been published. The 

"grandfathering" of Class V wells that do not meet the Class VI construction 

standards would only be needed for DOE test sites established before rulemaking 
was complete. If these wells include the ongoing mechanical integrity 

monitoring of annular fluid pressure and composition, and they pass periodic 

mechanical integrity testing, they should be able to follow the same permitting 

procedures to become operational Class VI wells. 

Response: EPA believes that submittal and review of monitoring data (as required at §146.90) and

the AoR reevaluation process (§146.84(e)) will provide an opportunity for an ongoing review of the

site and a dialogue between the Director and the owner or operator to ensure that the project is being

operated in a manner that protects USDWs from endangerment. EPA notes that changes to these

plans require a permit modification under §144.39, the public must be notified according to the

public comment procedures under 40 CFR 124.

Please see the final rule and the discussion of geologic site characterization in the preamble for

additional information.

EPA disagrees that every GS well should initially be permitted as a Class V well. The Agency

believes that the tailored Class VI requirements including extensive requirements for geologic site

characterization at §146.82, AoR evaluation at §146.84, and testing of the well during drilling at

§146.87 are appropriate to ensure that permitting authorities have the necessary information to

evaluate whether a specific site will allow safe injection of CO2. EPA adds that submittal and review

of monitoring data (as required at §146.90) and the AoR reevaluation process (§146.84(e)) will

provide an opportunity for an ongoing review of the site and a dialogue between the Director and

the owner or operator to ensure that the project is being operated in a manner that protects USDWs

from endangerment. Given this approach to permitting Class VI projects, EPA believes that the

requirements for grandfathering of construction at §146.81(c) are necessary and appropriate.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22576

Comment: Preamble Questions: Injection of CO2 for the purposes of enhanced oil and gas 

recovery (EOR/EGR), as long as any production is occurring, will continue to be 

permitted under the Class II program. EPA seeks comment on the merits of this 

approach since owners or operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being 

completely depleted. EPA Notice 48. 

NGWA Response: The transition of carbon dioxide injection wells from Class II 

(Enhanced Oil Recovery wells) to Class VI (carbon sequestration wells) will 

presumably be requested when production of the petroleum has ceased. Liquid 

carbon dioxide from a distant source, such as a power plant, can be stored in 

the depleted petroleum reservoir even after production has ceased, necessitating 

a change in classification of the injection well. The new use of the wells 

involves much longer storage time, and raises concerns about mechanical 

integrity and long term effects, including geochemical changes, on underground 

source of drinking water (USDWs). The reclassification should depend on a 

positive outcome from a Class V experimental program conducted in the depleted 

reservoir. See NGWA Comment Document (word document) Section titled 

""Classification of Injection Wells for Carbon Sequestration, Class II Injection 

Well Transition, and Grandfathering"" for further details. 
Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA adds that, following re-permitting as Class VI wells, these projects must be subject to the

operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure

requirements in the final GS rule. See the discussion of EPA's final regulatory approach in the

preamble to the GS rule for additional detail on these requirements.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22588

Comment: Proposed Rule: 146.81(b) 

Revision or Comment: Comment: NGWA supports the use of Class VI as "specifically 

for geologic carbon sequestration and believes that EOR and GS should be 

sequential and not concurrent" 

No rationale provided 

Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. The Agency believes that the nature and risks of

CO2 injection for the primary purpose of long term storage poses different risks than injection for

the primary purpose of ER, and therefore has developed new Class VI regulations to address these

unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is

significantly greater than for ER operations. Reservoir pressure conditions will also be different, with

Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II ER projects.

Commenter Name: Patrick Nugent Letter ID: 0143

Commenter Organization: Texas Pipeline Association (TPA) Comment ID: 23144

Other EPA Comment Codes and Descriptions: 2066 1.5.3.3 Grandfathering construction of Class

V wells (seeking comment) 

Comment: 11. Grandfathering of well construction standards for Class II and Class V 

wells should be provided without condition. EPA proposes to grandfather the well 

construction standards for a Class II and a Class V well that is converted to a 

Class VI well and requests comments on how this proposal may affect compliance 

with the proposed well construction standards for Class VI wells. TPA believes 

that the construction standards for an existing Class II or V well that is 

converted to a Class VI well should be accepted by EPA as having met the Class 

VI well construction requirements. The meaning of "grandfathering" an 

environmental requirement is just that: the requirements in place at the time 

continue to apply. If this were not the case, a viable sequestration project may 

not occur as development of a new well may be cost prohibitive. 
Response: EPA agrees that many Class II and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule provides for the construction of

these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to

the Director that the wells were engineered and constructed to meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the well as Class VI, many

of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

Commenter Name: Bonnie Lovelace Letter ID: 0152

Commenter Organization: Montana Department of Environmental Quality

(MDEQ)

Comment ID:

22108

Comment: 8. EPA seeks comment on grandfathering Class II wells as Class VI wells. This 

approach should be allowed with carefully tailored monitoring designed to 

address whatever site-specific differences may exist in construction of the 

wells. Other Class VI requirements should all be met. 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA adds that,

following re-permitting as Class VI wells, these projects must be subject to the operational, MIT,

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final

GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for

additional detail on these requirements.

Commenter Name: Jeff Moseley Letter ID: 0155

Commenter Organization: Greater Houston Partnership (GHP) Comment ID: 21259

Comment: 6. Provide more flexibility than has been proposed forprojects that transition 

from Class II to Class VI status. In order to fully reflect the petroleum 

industry's 35 year successful record of managing CO2 projects, the rule should 

provide flexibility for monitoring and other operational requirements and should 

provide greater flexibility for well construction requirements than has been 

proposed; 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are
designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the well as Class VI, many

of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

Commenter Name: James Dooley Letter ID: 0156

Commenter Organization: Joint Global Change Research Institute, Pacific

Northwest National Laboratory

Comment ID:

22624

Comment: rule is correct in clearly stating that only the construction requirements could 

be grandfathered assuming that all other aspects of the proposed Class VI rule 

are fulfilled (e.g., identifying and remediating all artificial penetrations 

within the AoR). This is a clear demonstration that the USEPA understands that 

simply injecting CO2 into the deep subsurface does not mean that Class II CO2 

driven EOR and Class VI GS are the same thing. However, it is not clear if the 

USEPA has gone far enough in differentiating between these two practices. In 

particular, the proposed Class VI rule should be explicit as to whether 

hydrocarbon recovery will still be allowed for wells/fields that have been 

permitted under Class VI. That is, a class VI well that is injecting CO2 in 

order to drive oil or natural gas towards adjacent production wells is not 

completely consistent with the overarching goal of the Class VI rule of 

permanently isolating CO2 from the atmosphere (i.e., some of the injected CO2 

will come up with the produced oil or gas, in some cases significant quantities 

of the injected CO2 will come up the production wells). The USEPA should 

consider whether it should explicitly state that the "grandfathering" of the 

construction requirements for Class II wells is also contingent upon the 

cessation of hydrocarbon production processes. Should this grandfathering only 

be allowed in depleted oil and gas fields that are no longer going to be used 

for enhanced hydrocarbon recovery and will exclusively be used for CO2 storage? 

This issue of grandfathering of Class II wells must also be a part of EPA’s 

needed deliberations about what else it needs to do in terms of rule making that 

lies outside of the SDWA to make CO2 stored in accord with the Class VI rule 

into something that can be used in the accounting framework of a national 

climate policy program. 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered
(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA adds that, following re-permitting as Class VI wells, these projects must be subject to the

operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure

requirements in the final GS rule. EPA believes this is necessary, because following re-permitting of

the project as GS, many of the unique factors of GS sites (e.g., increased reservoir pressures

associated with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water)

will result in an increased risk profile, warranting the specific requirements in the final GS rule.

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

assist Directors in evaluating 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 when determining 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.

EPA adds that GHG accounting and broader climate policy issues are outside the scope of the GS

rulemaking.

Commenter Name: Sandi Tabor Letter ID: 0162

Commenter Organization: Lignite Energy Council (LEC) Comment ID: 21299

Other EPA Comment Codes and Descriptions: 2066 1.5.3.3 Grandfathering construction of Class

V wells (seeking comment) 

Comment: regulated under the Class II program. For that matter, we also support granting 

state UIC directors the authority to grandfather the construction requirements 

for Class II and V wells when they are converted to full scale Class VI wells. 

Response: EPA agrees that many Class II and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule provides that the construction of

these wells be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the

Director that the wells were engineered and constructed to meet the requirements at §146.86(a) and

ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies

that only the construction requirements are grandfathered and that all other Class VI requirements

(reporting, monitoring, mechnical integrity testing, etc.) must be met following a determination
under §146.81(c).

Commenter Name: Michael Mudd Letter ID: 0167

Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 22456

Other EPA Comment Codes and Descriptions: 2066 1.5.3.3 Grandfathering construction of Class

V wells (seeking comment) 

Comment: Impact on Class II and Class V Wells p.43502, c. 1 

The Proposed Rule for Class VI wells should have no impact on existing or future 

Class II or Class V wells, which should be stated in the Proposed Rule in clear, 

unambiguous, and strong language. Furthermore, the Proposed Rule allows for the 

construction of existing Class II and Class V wells to be grandfathered, but 

there is no provision to allow the grandfathering of the existing siting, area 

of review, operations, or monitoring plan. These areas should be grandfathered, 

too. 

Response: EPA agrees that many Class II and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule provides for the construction of

these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to

the Director that the wells were engineered and constructed to meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the well as Class VI, many

of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23411

Comment: APPA recognizes that there are differences between Class II wells and Class VI 

wells that may necessitate additional requirements and safeguards as Class II 

wells transition to Class VI wells. 73 Fed. Reg. 43502. However, APPA recommends 

that the Final Rule include an option whereby Owners or Operators of Class II 

wells can make a demonstration that their well(s), if used for CO2 GS, will not 

pose a threat to USDWs. Such a case-by-case demonstration would allow for the 

carrying over of Class II well requirements where appropriate and protective of 

USDWs, maximizing the efficiency of such transitions while ensuring that USDWs 

remain protected. 

Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

engineered and constructed to meet the requirements at §146.86(a) and ensure protection of USDWs,
in lieu of requirements at §146.86(b) and §146.87(a).

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 adds that, following re-permitting as Class VI wells, these

projects would be subject to the operational, MIT, monitoring, reporting, plugging, and postinjection site care and site closure requirements in the final GS rule.

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

assist Directors in evaluating 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 determine 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.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24139

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.25 GEOLOGIC SEQUESTRATION IN OIL OR GAS

RESERVOIRS WITHOUT 

ENHANCED RECOVERY OF OIL OR NATURAL GAS 

API Comments: WELLS USED FOR GEOLOGIC SEQUESTRATION AND MEETING THE 

CLASSIFICATION CRITERIA OF SECTION 146.5(B)(5) SHALL BE SUBJECT TO THE

FOLLOWING 

REQUIREMENTS: 

(A) EXISTING WELLS THAT MEET OR EXCEED THE CONSTRUCTION REQUIREMENTS

OF § 146.22 

SHALL BE SUBJECT TO PART 146, SUBPART H [AS REVISED BY API] EXCEPT SECTIONS

146.86 AND 146.87. 

(B) NEW WELLS MUST MET THE CONSTRUCTION REQUIREMENTS OF SECTION 146.22

AND ARE 

SUBJECT TO PART 146, SUBPART H [AS REVISED BY API] EXCEPT SECTIONS 146.86

AND 

146.87 

Rationale: Details of what would be required of "Class IIB" wells are to be 

worked out during future discussions of the Multi-Stakeholder Discussion Group 

(MSDG). However, API offers this language which is consistent with changes API 
had suggested before discussions with the MSDG began (see Section 146.81(c)). 

These suggestions are - as noted - contingent on EPA‘s adoption of API‘s changes 

to Part 146, Subpart H. 

Response: As described above regarding the suggested edit at 144.6, EPA did not make the

suggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of longterm storage should be regulated under Class II requirements because Class II requirements do not

address the unique risks posed by GS while ensuring protection of USDWs from endangerment.

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24232

Comment: Rule Provisions: 146.81(c) 

EPA Preamble Question: 17. EPA also seeks comment on how the proposed 

grandfathering provisions for existing wells (construction requirements) may 

affect compliance with the above, proposed construction requirements. EPA Notice 

43509. 

API Response: Grandfathering should be handled on a case-by-case basis. The 

standard for grandfathering should be demonstrated performance of the well at 

protecting USDWs. Because the act of injection would be the same for CO2 EOR and 

CO2 storage, Class II CO2 EOR wells should be deemed to meet the requirements of 

146.86 and 146.87 upon notification. The purpose of grandfathering is to 

recognize that some wells may not meet construction requirements of Class VI 

wells, but the performance of Class II CO2 injection wells justifies their use 

as Class II CO2 Storage wells ("Class IIb") or Class VI wells if EPA does not 

adopt a special subclass for storage under the Class II program. 

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

assist Directors in evaluating 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 determine 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.
In response to the comment that GS wells should be regulated as Class II wells, EPA believes that

injection for the primary purpose of long term storage is sufficiently different from Class II ER

operations and warrants tailored requirements. For example, the volume of CO2 anticipated to be

injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure

conditions will also be different, with Class VI injection operations involving large volumes of CO2

and likely having higher pressures within their storage formations than Class II ER projects, which

may result in fluid movement that endangers a USDW.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25173

Other EPA Comment Codes and Descriptions: 2062 1.5.3.1 Grandfathering construction of Class

I wells (seeking comment) 

Comment: C. EPA is proposing to give the Director discretion to carry over or 

"grandfather" the construction requirements (e.g., permanent, cemented well 

components) for existing Class I and Class II wells seeking a permit for GS of 

CO2, provided he/she is able to make a determination that these wells would not 

endanger USDWs. 

NYSDEC-DMN Response: NYSDEC-DMN agrees that this discretion is appropriate and 

necessary when reviewing other UIC Class wells for use as UIC Class VI wells. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c).

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24321

Other EPA Comment Codes and Descriptions: 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: The other transition issue involves the substantive requirements that should 

apply to existing, currently-permitted wells that are converted to GS service. 

The preamble indicates that "the owner or operator would need to follow the 

permitting process outlined in today’s proposal to receive a Class VI permit," 

but EPA proposes "to give the Director discretion to carry over or ‘grandfather’ 

the construction requirements for existing wells if the Director makes a 

determination "that these wells would not endanger USDWs." 73 Fed. Reg. at 

43502. This approach seems backwards: having recognized the problems associated 

with the application of new well construction standards to existing wells, EPA 

should recognize that the well construction standards for all well classes are 

designed to ensure that USDWs are not endangered. Consequently, in the absence 

of some specific evidence of a construction problem that might endanger a USDW, 
there is no basis to question the construction of an existing, previouslypermitted injection well, and any "grandfathering" with respect to the Class VI 

construction requirements should be virtually automatic. 

In addition, it is important to recognize that the need and justification for 

"grandfathering" is not limited to construction requirements. There are also 

proposed Class VI operational and monitoring requirements that would require the 

substantial modification - if not outright abandonment - of many existing CO2 

injection wells (the proposed requirement for continuous monitoring of annulus 

pressure is a conspicuous example). In every case, the wells at issue have 

already been constructed consistent with requirements that UIC program officials 

have determined to be sufficient to prevent endangerment of USDWs. In view of 

this fact, there should be a regulatory presumption - absent some specific 

information to the contrary - that continued operation of wells already in CO2 

service for CO2 injection will also be protective of USDWs. 

The proposed Class VI regulations would require a relatively elaborate 

demonstration that injected CO2 will remain isolated from USDWs, and some 

supplementation of the permit requirements for existing wells may be appropriate 

consistent with the broad geological containment standards for Class VI wells. 

To the extent these or other supplemental requirements are truly necessary, they 

could and should be imposed through modification or supplementation of existing 

permit conditions rather than through the wholesale application of Class VI 

program requirements to pre-existing activities already found to be protective 

of USDWs. Accordingly, we recommend that the Final Rule include a presumption 

that wells already in CO2 service be allowed to transition to Class VI status-- 

or, in the case of Class II wells, to remain in Class II and be used for 

GS-based on their existing permit conditions, subject only to additional 

requirements as necessary to demonstrate geologic containment of the injected 

CO2 stream. 

Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. Furthermore, the final GS rule allows the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered from Class II wells. Following re-permitting of the well

as Class VI, many of the unique factors of GS sites (e.g., increased reservoir pressures associated

with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water) will result in

an increased risk profile, warranting the specific requirements in the final GS rule. Therefore,

following re-permitting as Class VI wells, these projects would be subject to the operational, MIT,

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final

GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for

additional detail on these requirements.

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 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 longterm storage of large volumes of CO2. The guidance describes the 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24524

Comment: Rule Provisions or Federal Register Cite: 146.81(c) 

EPA Preamble Question: 17. EPA also seeks comment on how the proposed 

grandfathering provisions for existing wells (construction requirements) may 

affect compliance with the above, proposed construction requirements. EPA Notice 

43509. 

CSC Response: By definition, the construction of previously-permitted wells has 

already been determined to be sufficient for protection of USDWs. Consequently, 

additional construction-related requirements should not be imposed in the 

absence of specific evidence of a construction-related deficiency creating a 

potential for endangerment. Because the act of injection would be the same for 

CO2 EOR and CO2 storage, wells in CO2 service constructed to Class II well 

standards should presumptively be sufficient to protect USDWs. 

Response: As described above, EPA agrees that many Class II wells are designed and constructed to

withstand exposure to CO2. The final GS rule provides for the construction of these wells to be

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

the wells were engineered and constructed to meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). Following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

Commenter Name: John R. Baza Letter ID: 0193

Commenter Organization: Utah Division of Oil, Gas, and Mining Comment ID: 23910

Comment: The proposed rule allows the director of the program the discretion to 

"grandfather" the construction requirements of existing Class II wells to Class 

VI wells as long as a determination is made that these wells would not endanger 
a USDW. The Division agrees with this proposal considering that an existing 

Class II well for EOR would not be allowed to endanger a USDW. 

Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a). 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 adds that,

following re-permitting as Class VI wells, these projects would be subject to the operational, MIT,

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final

GS rule.

Commenter Name: Andy Horn Letter ID: 0196

Commenter Organization: Colorado Ground Water Association (CGWA) Comment ID: 23931

Comment: Conversion of existing oil and gas wells and/or EOR wells to CO2 injection wells 

should be evaluated on a detailed case-by-case basis. Review should include all 

well construction records, performance of well evaluation and mechanical 

integrity testing and cement bond logging, and in the event the well is 

retained, workover should be performed. 

Response: EPA agrees that any decision to convert a well for long term storage of CO2 should be

made in the context of all available information about the site and history of injection. The final GS

rule provides for the construction of these wells to be grandfathered per §146.81(c), provided the

owner or operator can demonstrate to the Director that the wells were engineered and constructed to

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

§146.86(b) and §146.87(a).

EPA clarifies that other requirements (i.e., beyond the construction requirements) will not be

grandfathered. Following conversion of the project to Class VI, many of the unique factors of GS

sites (e.g., increased reservoir pressures associated with large volumes of stored CO2 and the

corrosivity of CO2 in the presence of water) warrant the specific operational, MIT, monitoring,

reporting, plugging, post-injection site care, and site closure requirements in the final GS rule.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24587

Comment: Rule Provisions: 146.81(c) 

EPA Rule Issue: 17. EPA also seeks comment on how the proposed grandfathering 

provisions for existing wells (construction requirements) may affect compliance 

with the above, proposed construction requirements. EPA Notice 43509. 
Anadarko Petroleum Corporation (APC) Response: Anadarko does not believe the 

construction requirements above current Class II standards are necessary (in 

particular cement to surface). The purpose of grandfathering is to recognize 

that some wells may not meet construction requirements of Class VI wells, but 

the performance of Class II CO2 injection wells justifies their use as Class II 

CO2 Storage wells ("Class IIb") or Class VI wells if EPA does not adopt a 

special subclass for storage under the Class II program. Class II EOR has proven 

successful at preventing contamination of USDWs. As mentioned in response to EPA 

Notice 43502, utilizing a sub-class of Class II (Class II GS) would provide a 

means to handle the additional monitoring requirements from sequestration 

applications. 

Grandfathering should be handled on a case-by-case basis. The standard for 

grandfathering should be demonstrated performance of the well at protecting 

USDWs. Because the act of injection would be the same for CO2 EOR and CO2 

storage, Class II CO2 EOR wells should be deemed to meet the requirements of 

146.86 and 146.87 upon notification. 

Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a). 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 adds that,

following re-permitting as Class VI wells, these projects would be subject to the operational, MIT,

monitoring, reporting, plugging, and post-injection site care and site closure requirements in the final

GS rule.

Commenter Name: John King Letter ID: 0211

Commenter Organization: Shell Exploration and Production Company

(SEPCo)

Comment ID:

22759

Other EPA Comment Codes and Descriptions: 1210 1.1.1 Comments about the proposed rule 

Comment: C. The Proposed Class VI Requirements Are Far More Burdensome than Necessary to 

Protect USDWs. 

As the preamble acknowledges, the actual human health and ecological risks 

associated with GS are relatively remote and can be addressed effectively 

through measures implemented to protect USDWs. 73 Fed. Reg. at 43497-98. 

Unfortunately, the proposed rule seems to proceed from the premise that the 

strictest UIC regulations in existence - those for hazardous waste injection - 

should serve as the starting point for the development of the Class VI 

regulations. Given the vast knowledge and experience developed through the 
handling of CO2 in different operations, SEPCo contends that the more logical 

starting point for development of the Class VI regulations is the Class II 

regulations. 

As the proposed rule recognizes, CO2 injection operations have been conducted 

pursuant to the Class II regulations for many years, and experience with 

thousands of wells injecting hundreds of millions of tons of CO2 demonstrates 

that the Class II regulations - as applied to CO2 injection - are adequate to 

protect USDWs This is certainly true with respect to the basic construction, 

operating, monitoring, and mechanical integrity testing requirements for 

injection wells; we believe that what "works" in terms of the construction and 

operation of a CO2 injection well does not depend on the purpose for which CO2 

is being injected. 

Unfortunately, the proposed Class VI requirements are far more stringent than 

the Class II requirements, a fact that gives rise - under the proposed rule - to 

the need to "grandfather" Class II CO2 injection wells that remain in service 

for GS purposes after oil or gas production has ceased. Rather than resembling 

the Class II requirements, the proposed Class VI requirements are as stringent 

as those for hazardous waste injection in most respects. Indeed, many of the 

construction, mechanical integrity, and monitoring and financial assurance 

requirements proposed for Class VI wells are even more comprehensive and 

stricter than those for hazardous waste injection wells. While some of these 

more burdensome requirements are legitimately related to concerns about the 

mobility of CO2 or the anticipated scale of GS operations, many - as discussed 

in Part III of these comments - are not. 

Recommendation: 

The Class VI requirements addressing issues such as well construction and 

mechanical integrity testing should be no different than the Class II 

requirements. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the well as Class VI, many

of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.
Commenter Name: Edward Steadman Letter ID: 0220

Commenter Organization: The Energy and Environmental Research Center at the

University of North Dakota

Comment ID:

21576

Comment: advancement of CCS need to be embraced. This reality needs to be further 

embraced when one contemplates a streamlined approach, such as "grandfathering" 

for Class II wells that may be useful for sequestration beyond the EOR project. 

Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a).

EPA adds that promotion of CCS is not within the scope of the GS rulemaking. The purpose of the

rulemaking is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs

from endangerment.

Commenter Name: Jonathon Palm Letter ID: 0222

Commenter Organization: Nevada Division of Environmental Protection, Bureau

of Water Pollution Control

Comment ID:

21642

Other EPA Comment Codes and Descriptions: 2066 1.5.3.3 Grandfathering construction of Class

V wells (seeking comment) 

Comment: 3. Existing Class II & V wells should not be grandfathered in on long-term CO2 

injection projects. Injection into a Class II oil well may be appropriate for 

short-term project in a producing oil/gas field, but CO2 injection will outlast 

a producing field and may not have been constructed to specs. All CO2 wells must 

be specifically designed. 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered,

per §146.81(c). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies that only

the construction requirements are grandfathered and that all other Class VI requirements (reporting,

monitoring, mechnical integrity testing, etc.) must be met following a determination under

§146.81(c).

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21651

Comment: HEI requests that EPA consider the foregoing discussion of a subclass or Class 

II-B wells for oil and gas formations for future rulemaking. However, in the 

context of the current Proposed Rule, we submit the following recommendations on 

the question of grandfathering. 

(ii) Grandfathering - Transitioning from EOR and Storage to Exclusively CO2 Storage 
After the EOR and Storage projects conclude production of oil or gas, injection 

of CO2 may continue at the option of the operator to utilize fully all available 

pore space. EPA regulations should facilitate this transition from EOR and 

Storage to exclusively storage operations when EOR/EGR operations are completed. 

EPA’s decision to allow grandfathering of construction requirements in sections 

146.81 and 146.86 of the Proposed Rule is an excellent example of both 

protective and reasonable regulation. HEI supports EPA’s proposal and recommends 

that EPA expand the grandfathering provisions to encourage and facilitate 

continued injection of CO2 exclusively for storage when EOR/EGR operations 

cease. 

Specifically, the Proposed Rule should be modified also to allow grandfathering 

of sections 146.88(e) and (f) (continuous recording devices and down-hole 

automatic shut-off devices, respectively) regarding Operations; and Section 

146.89(b) and (c) (continuous monitoring and specific yearly tests, 

respectively) regarding Mechanical Integrity. Existing, operationallycompliant, Class II EOR-wells will continue to protect USDWs, as established by 

their operational histories, even when injection is for the exclusive purpose of 

CO2 sequestration without the foregoing additional Operation or Mechanical 

Integrity requirements. In addition, the following sections of the Proposed 

Rule simply will not be applicable or pertinent at the time of transition 

because these provisions presume that no injection has commenced. These sections 

are as follows: 

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

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

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

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

These provisions should not and cannot apply when a Class II EOR and Storage 

project transitions to an exclusively storage project because, as a practical 

matter, performance of certain "baseline measurements," "model predictions," 

"witnessing of logging and testing," and "corrective actions" will not be 

possible prior to injection of CO2. 

In sum, EPA should expand the grandfathering provisions to encourage continued 

storage of CO2 after EOR/EGR operations have ceased. Most of the existing Class 

II requirements that were appropriate for regulation of EOR and Storage will 

continue to operate effectively and to safeguard USDWs during exclusively 

storage operations. Finally, appropriately expanded grandfathering will 

facilitate optimal utilization of these proven oil and gas reservoirs for 

geologic sequestration of CO2. 

CCS in connection with EOR provides a forward-looking energy policy for the 

United States, as it will significantly reduce CO2 emissions with the added 

benefit of increasing energy security through increased domestic oil production. 
Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., monitoring, operational, and AoR requirements) should

also be grandfathered. Following re-permitting of the well as Class VI, many of the unique factors of

GS sites (e.g., increased reservoir pressures associated with large volumes of stored CO2 and the

corrosivity of CO2 in the presence of water) will result in an increased risk profile, warranting the

specific requirements in the final GS rule. Following re-permitting as Class VI wells, these projects

must be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection site care

and site closure requirements in the final GS rule. See the discussion of EPA's final regulatory

approach in the preamble to the GS rule for additional detail on these requirements.

EPA adds that promotion of energy security and a broader energy policy are not within the scope of

the GS rulemaking. The GS rule focuses on ensuring that, where GS is deployed, it is conducted in a

manner that protects USDWs from endangerment.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21715

Comment: BP requests that EPA consider the foregoing discussion of a subclass or Class 

II-B wells for oil and gas formations for future rulemaking. However, in the 

context of the current Proposed Rule, we submit the following recommendations on 

the question of grandfathering. 

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

Storage 

After the EOR and Storage projects conclude production of oil or gas, 

injection of CO2 may continue at the option of the operator to utilize 

fully all available pore space. EPA regulations should facilitate this 

transition from EOR and Storage to BP’s Comments To EPA’s Proposed Rule 

exclusively storage operations when EOR/EGR operations are completed. EPA’s 

decision to allow grandfathering of construction requirements in sections 

146.81 and 146.86 of the Proposed Rule is an excellent example of both 

protective and reasonable regulation. BP supports EPA’s proposal and 

recommends that EPA expand the grandfathering provisions to encourage and 

facilitate continued injection of CO2 exclusively for storage when EOR/EGR 

operations cease. 

Specifically, the Proposed Rule should be modified also to allow grandfathering 

of sections 146.88(e) and (f) (continuous recording devices and down-hole 

automatic shut-off devices, respectively) regarding Operations; and Section 

146.89(b) and (c) (continuous monitoring and specific yearly tests, 

respectively) regarding Mechanical Integrity. Existing, operationally-compliant, 

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

operational histories, even when injection is for the exclusive purpose of CO2 
sequestration without the foregoing additional Operation or Mechanical Integrity 

requirements. In addition, the following sections of the Proposed Rule simply 

will not be applicable or pertinent at the time of transition because these 

provisions presume that no injection has commenced. These sections are as 

follows: 

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

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

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

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

These provisions should not and cannot apply when a Class II EOR and Storage 

project transitions to an exclusively storage project because, as a practical 

matter, performance of certain "baseline measurements," "model predictions," 

"witnessing of logging and testing," and "corrective actions" will not be 

possible prior to injection of CO2. 

In sum, EPA should expand the grandfathering provisions to encourage continued 

storage of CO2 after EOR/EGR operations have ceased. Most of the existing Class 

II requirements that were appropriate for regulation of EOR and Storage will 

continue to operate effectively and to safeguard USDWs during exclusively 

storage operations. Finally, appropriately expanded grandfathering will 

facilitate optimal utilization of these proven oil and gas reservoirs for 

geologic sequestration of CO2. 

CCS in connection with EOR provides a forward-looking energy policy for the 

United States, as it will significantly reduce CO2 emissions with the added 

benefit of increasing energy security through increased domestic oil production. 

Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., monitoring, operational, and AoR requirements) should

also be grandfathered. Following re-permitting of the well as Class VI, many of the unique factors of

GS sites (e.g., increased reservoir pressures associated with large volumes of stored CO2 and the

corrosivity of CO2 in the presence of water) will result in an increased risk profile, warranting the

specific requirements in the final GS rule. Following re-permitting as Class VI wells, these projects

must be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection site care

and site closure requirements in the final GS rule. See the discussion of EPA's final regulatory

approach in the preamble to the GS rule for additional detail on these requirements.

EPA adds that promotion of energy security and a broader energy policy are not within the scope of

the GS rulemaking. This rule focuses on ensuring that, where GS is deployed, it is conducted in a

manner that protects USDWs from endangerment.
Commenter Name: Michael E. Moore Letter ID: 0232

Commenter Organization: Blue Source Comment ID: 21897

Other EPA Comment Codes and Descriptions: 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: The preamble to EPA’s proposal suggests that as long as production is occurring 

and reservoirs are not depleted, Class II permitting provisions apply; only when 

a reservoir is depleted may the new proposed Class VI CCS provisions apply. 

[FN2] Because the grandfathering of the Class VI requirements is relatively 

narrow, we interpret EPA’s proposal to mean that CO2-EOR operators (and others 

associated with such projects, including industrial sources) effectively will be 

disqualified from participating in CCS. This disqualification, in turn, 

suggests that: (i) capped industrial sources who intend to use CO2-EOR as their 

means of compliance with likely forthcoming cap-and-trade legislation will be 

deprived of the ability to do so, and (ii) uncapped industrial sources under 

cap-and-trade legislation may be disqualified from seeking treatment as 

providers of offsets to regulated sources. 

[FN2: See discussion in Preamble at 48-49.] 

The inadvertent impact of EPA’s proposal is to strand CO2-EOR by not giving it 

the option of being included in CCS. This would be an unfortunate outcome for 

the environment and CCS. According to a recent study by the U.S. Department of 

Energy (DOE), CO2-EOR has the potential to provide a significant storage market 

for carbon dioxide. [FN3] DOE estimates that the size of this market is on the 

order of 7,500 million metric tons of carbon dioxide between 2008 and 2030. 

CO2-EOR, in other words, is not a niche in the battle to combat climate change; 

it instead is poised to play a critical role, particularly in the early years of 

the deployment of CCS technology. 

The commercial aspects of CO2-EOR in helping to finance, fund, and build firstmover CCS infrastructure which, in turn, could be used by broader CCS operations 

(including deep saline, for example) cannot be overlooked. DOE has estimated 

that CO2 sales for EOR would support the "early market entry" of up to fortynine (one GW size) installations of CCS technology in the coal-fired utility 

sector alone. [FN4] Given that Europe is looking at funding twelve 

demonstration CCS projects in the years ahead, we believe that forty-nine 

projects is a significant number of projects that could jump-start CCS as a 

climate mitigation solution. 

[FN3: See "Storing CO2 With Enhanced Oil Recovery," DOE/NETL-402/1312/02-0708, 

at 1 (Feb. 7, 2008) (available at 

http://www.netl.doe.gov/energy-analyses/pubs/storing%20co2%20w%20eor_final.pdf) 

.] 

[FN4 Id.] 

Giving CO2-EOR operators the option of participating in storage would not 

imperil drinking water aquifers as such assessments are already part of the 

Class II approval process. Indeed, since CO2-EOR operations are by definition 

brownfields, not greenfields, it might be expected that the risk profile of such 
projects - in terms of potential drinking water impacts - might be lower 

initially than other sites, although site assessments would of course still need 

to be done. 

Blue Source is concerned that these (and other) significant CO2-EOR benefits 

could be squandered if EPA proceeds with its proposed treatment of this proven 

technology.[FN5] 

[FN5: A large volume of literature, which won’t be repeated here, documents the 

successful, safe and environmentally sound use of CO2-EOR through the US for 

many decades. Moreover, a significant portion of US domestic oil production is 

the result of CO2-EOR: according to the 2006 EOR survey published by the Oil & 

Gas Journal, approximately 237,000 barrels per day of incremental oil production 

is being produced by eighty six CO2-EOR projects that are distributed broadly 

across the United States. CO2-EOR is not just about the Permian Basin, in other 

words.] 

b. Suggested Solution 

Blue Source encourages EPA to provide CO2-EOR operators with the option of 

participating in CCS. Such participating could take several forms. For 

example, operators (and other project participants) could be given the right to 

"opt into" what might be called an "EOR-plus" regulatory option under the 

existing Class II well program. The EOR-plus regulatory option would of course 

be limited to anthropogenic CO2 and might include the following additional 

requirements: (i) up-front suitability assessment for storage operations, 

including an analysis of the reservoir’s risk profile and an assessment of 

whether appropriate storage rights have been obtained (if necessary); and (ii) 

measuring, monitoring and verification requirements. 

This option could be selected by the operator at any time - e.g., prior to, 

during, or at the conclusion of a CO2-EOR flood. 

This option also could be implemented by the primacy States under the existing 

Class II program. This makes sense because the States already have decades of 

experience in regulating Class II; State regulators also possess the necessary 

geologic data and expertise to ensure that CO2-EOR storage operations did not 

imperil environmental end points of concern. 

In lieu of a more formalistic EOR-plus regulatory option, EPA could provide even 

greater flexibility by indicating that CO2-EOR operations would have the 

ability, on a case-by-case basis, to demonstrate that they were engaged in 

storage by meeting a performance-based storage and environmental standard, 

focused on drinking water aquifers. Alternatively, the preamble to the final 

rule could provide that the rule’s applicability was limited to deep saline, and 

that nothing in the rule was intended to impact the ability of CO2-EOR to 

qualify as storage, but that this topic would be addressed in a separate 

rulemaking, which EPA then would undertake expeditiously. 

Finally, Blue Source is not proposing that any changes be made to the existing 
Class II regulations, which would remain available for those operators who did 

not elect to opt into the EOR-plus regulatory (or comparable) scheme. Blue 

Source also is not suggesting that business-as-usual CO2-EOR qualify as storage 

because we recognize that existing Class II requirements fall short of what may 

be required to demonstrate storage. 

Conclusion 

Blue Source encourages EPA to provide CO2-EOR operators with the option of 

participating in CCS because doing so would provide the most environmentally 

sensitive method of jump-starting CCS, a critical climate mitigation technology. 

Failure of EPA to do so could stall the development, deployment and funding of 

critical CCS infrastructure and lead to unnecessary further industrial emissions 

of carbon dioxide. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. However, the Agency believes that the nature and risks of CO2 injection for the primary

purpose of long term storage poses different risks than injection for the primary purpose of ER, and

therefore has developed new Class VI regulations to address these unique risks. For example, the

volume of CO2 anticipated to be injected for long term storage is significantly greater than for ER

operations. Reservoir pressure conditions will also be different, with Class VI injection operations

involving large volumes of CO2 and likely having higher pressures within their storage formations

than Class II ER projects, which may lead to fluid movement that endangers a USDW. 

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 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 longterm 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.

EPA clarifies that the purpose of the GS rule is to ensure protection of USDWs from endangerment

and not to promote or incentivize GS deployment. However, the Agency believes that establishing a

regulatory framework for the future development and deployment of CCS technology may provide

the regulatory and jurisdictional certainty needed to foster development and deployment of CCS

while ensuring USDW protection.
Commenter Name: Philip Papadeas Letter ID: 0238

Commenter Organization: Sandia Technologies, LLC Comment ID: 23347

Comment: For grandfathering of Class II wells to Class VI designation, in my judgment 

Class II wells are not constructed very stringently since they are typically 

converted oil and gas wells which have outlived their useful lives in 

hydrocarbon production. Cement bond in the annulus and isolation is typically 

not as good as Class I wells where continuous cement bond must be present 

allowing for 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). 

The final GS rule provides that the construction of these wells be grandfathered per §146.81(c),

provided the owner or operator can demonstrate to the Director that the wells were engineered and

constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of

requirements at §146.86(b) and §146.87(a). EPA clarifies that only the construction requirements are

grandfathered and that all other Class VI requirements (reporting, monitoring, mechnical integrity

testing, etc.) must be met following a determination under §146.81(c).

Commenter Name: Angie Burckhalter Letter ID: 0239

Commenter Organization: Oklahoma Independent Petroleum Association Comment ID: 23216

Comment: Finally, we think EPA’s proposed grandfathering requirements are too restrictive 

and will prevent or discourage entities from converting Class II EOR wells to 

Class VI wells. EPA has proposed to only allow the construction requirements to 

be "grandfathered" based on the UIC program director’s discretion while all 

other requirements would apply. There is no reason to limit the grandfathering 

of requirements for existing CO2 EOR wells that have proven to pose no 

endangerment to underground sources of drinking water. We think EPA should 

expand the scope of grandfathering requirements for these types of wells and 

limit additional Class VI requirements. Again, we appreciate the opportunity to 

Response: EPA agrees that many Class II wells are designed and constructed to withstand exposure

to CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the well as Class VI, many

of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on
these requirements.

Commenter Name: Mike Nasi Letter ID: 0254

Commenter Organization: Clean Coal Technology Foundation of Texas Comment ID: 22367

Comment: 4. Dual Purpose Wells and Grandfathering of Certain Class II Wells 

It is clear from the preamble to the proposed rule that EPA recognizes the 

valuable role that oil and gas reservoirs can play in the GS of CO2. The issue 

that is not clear is how or whether a well can be used for both enhanced oil 

recovery as well as sequestration of CO2. CO2 that is injected for EOR can, at 

the same time, be sequestered for long term storage, yet there is no recognition 

by EPA of such a concurrent dual role for a well. Existing Class II regulations 

governing injection of CO2 in oil and gas reservoirs have proven to be 

successful in protecting USDWs. EPA should consider creating a regulatory system 

that authorizes a well to serve the dual purpose of CO2 sequestration as well as 

enhanced recovery of oil or natural gas. Furthermore, EPA should propose 

regulations that would authorize the grandfathering of Class II wells, without 

requiring technically unnecessary changes to equipment and monitoring 

procedures. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS

sites. EPA agrees that many Class II wells are designed and constructed to withstand exposure to

CO2. The final GS rule provides for the construction of these wells to be grandfathered per

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

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

in lieu of requirements at §146.86(b) and §146.87(a).

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

assist Directors in evaluating 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 determine 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.

Commenter Name: Matt Toner Letter ID: 0506
Commenter Organization: Hydrogen Energy International Comment ID: 21185

Comment: EPA has recognized this valuable role that oil and gas reservoirs can play in 

the geological storage of CO2. And Hydrogen Energy would like to encourage that 

EPA go significantly further in facilitating the use of these reservoirs. When 

CO2 is injected for enhanced oil and gas recovery it could at the same time be 

sequestered for long-term storage at the option of the operator. 

EPA should recognize this concurrent dual purpose, enhanced oil and gas 

recovery, and designed storage, and allow for this dual purpose under existing 

Class II UIC rules. Furthermore, EPA regulations should facilitate 

grandfathering from dual purpose production and storage, the storage only sites, 

when enhanced oil or gas operations are completed. 

In the course of the typical enhanced oil recovery operation, even when there is 

no intent to sequester 30 to 50 percent of the injected CO2 remains in the 

reservoir after production operations cease. The remainder is either miscibly 

dissolved within the produced oil or recycled for use in other reservoirs, it's 

not emitted to the atmosphere. 

But today 90 percent of the CO2 used in enhanced recovery operations is produced 

from naturally occurring accumulations. Rather than using these naturally 

occurring accumulations society can mitigate greenhouse gas emissions by 

substituting anthropogenic sources. In addition, injection can continue, upon 

the completion of production operations, to fully utilize all existing pore 

space, what we call EOR plus storage. 

Response: EPA believes that injection of CO2 for the primary purpose of enhancing oil and gas

recovery should remain under the Class II Program. However, the Agency disagrees that wells

injecting CO2 for the primary purpose of long term storage should be regulated under Class II

requirements. EPA recognizes that the oil and gas industry has decades of experience injecting CO2

for the purpose of EOR, and that sites used for EOR may be suitable for GS and may be among the

first GS sites. EPA also recognizes that a by-product of EOR activities is that a certain percentage of

the CO2 is trapped in the receiving formation. 

The Agency believes that the nature and risks of CO2 injection for the primary purpose of long term

storage poses different risks than injection for the primary purpose of ER, and therefore has

developed new Class VI regulations to address these unique risks. For example, the volume of CO2

anticipated to be injected for long term storage is significantly greater than for EOR operations.

Reservoir pressure conditions will also be different, with Class VI injection operations involving

large volumes of CO2 and likely having higher pressures within their storage formations than Class

II EOR projects. 

Commenter Name: Matt Toner Letter ID: 0506

Commenter Organization: Hydrogen Energy International Comment ID: 21188

Other EPA Comment Codes and Descriptions: 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: The existing Class II regulations governing injection of CO2 in oil and gas 

reservoirs have proven successful at protecting underground sources of drinking 

waters. These regulations should allow for the dual purpose of sequestration if 
anthropogenic CO2 is used. 

Hydrogen Energy also recommends that EPA expand grandfathering to facilitate 

transition from production and storage to storage only sites, which will 

incentive the use of these reservoirs for long-term CO2 storage. The proposed 

grandfathering of Class II Wells should go beyond just the construction 

requirements to include, at a minimum, operating and mechanical integrity 

requirements for existing, operationally compliant Class II EOR CO2 Injection 

Wells. The Class VI requirements would require technically unnecessary changes 

to equipment and monitoring procedures. 

Some authors have identified risks with using oil and gas reservoirs for CO2 

sequestration due to the presence of inactive wells. Proper plugging and 

abandonment of inactive wells is a prudent method which can ensure this risk is 

effectively managed. In addition, the oil and gas industry has developed 

techniques to quickly isolate, effectively repair, and remediate these issues 

and their unlikely occurrence. 

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. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

EPA agrees that many Class I, Class II, and Class V experimental technology wells are designed and

constructed to withstand exposure to CO2. The final GS rule allows the construction of these wells

to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director

that the wells were engineered and constructed to meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered because they Class II requirements are not tailored to

address the unique risks posed by long term CO2 storage to USDWs. Following re-permitting of the

project as GS, many of the unique factors of GS sites (e.g., increased reservoir pressures associated

with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water) will result in

an increased risk profile, warranting the specific requirements in the final GS rule.

Commenter Name: Talib Syed Letter ID: 0537

Comment ID: 21471

Comment: That leads me to mechanical integrity. The integrity, the mechanical integrity 

is going to be a critical component. I believe right around the well hole in the 

casing and the type of cements that you use and the potential for flow on the 

backside due to back flow etcetera becomes critical. So I am not ruling out, you 

know, transitioning or using EOR type wells for geosequestration, but you have 
got to be careful on looking at those wells and just not saying, okay, I have 

got these wells, they are for EOR purposes and I am just going to straight away 

transition them for geosequestration. If you've got a custom designed well, that 

is the way I would go, but I would not rule out using Class II EOR wells, but 

pay a lot of close attention to it. 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered

(per 146.81(c)). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure

protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). Following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

Comment Code: 2066 1.5.3.3 Grandfathering construction of Class V wells (seeking comment) 

Individual Comments

Commenter Name: Karl R. Moor Letter ID: 0109

Commenter Organization: Southern Company, on behalf of Edison Electric

Institute (EEI)

Comment ID:

22007

Comment: Prescriptive regulations and defaults often have unintended negative 

consequences. For example, consider EPA’s proposal to grandfather only 

construction requirements for wells that currently are permitted as Class V 

experimental storage wells. This limited grandfathering, if part of the final 

rule, would render many experimental storage projects as stranded investments 

and would limit the number of formations available for future storage. A better 

approach would be to allow Class V permit holders to make their case to EPA, 

based on the specific characteristics of their site, that the formation can 

provide long-term storage for carbon dioxide without endangering underground 

sources of drinking water. In this way, regulatory flexibility can serve to 

protect water sources without unduly limiting the number and type of formations 

available for carbon dioxide storage. 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a).

Commenter Name: Leslie Savage Letter ID: 0122
Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24758

Other EPA Comment Codes and Descriptions: 2060 1.5.3 Comments on grandfathering of

existing wells (seeking comment); 2062 1.5.3.1 Grandfathering construction of Class I wells (seeking

comment); 2064 1.5.3.2 Grandfathering construction of Class II wells (seeking comment) 

Comment: Subpart H--Criteria and Standards Applicable to Class VI Wells 

§146.81 Applicability. 

(a) This subpart establishes criteria and standards for UIC programs to regulate 

Class VI CO2 GS injection wells. (b) This subpart applies to wells used to 

inject CO2 specifically for the purpose of GS, i.e., the long-term containment 

of a gaseous, liquid or supercritical CO2 stream in subsurface geologic 

formations. (c) This subpart applies to owners and operators of permit or ruleauthorized Class I industrial, Class II, or Class V experimental CO2 injection 

projects who seek to apply for a Class VI geologic sequestration permit for 

their well or wells. If the Director determines that USDWs will not be 

endangered, such wells are exempt, at the Director's discretion, from the casing 

and cementing requirements at §§146.86(b) and 146.87(a)(1) through (3). 

{RRC agrees that the Director evaluating a permit application to use existing 

injection wells for geologic sequestration should have the discretion to exempt 

wells from Class I industrial, Class II or Class V wells from the proposed 

casing and cementing requirements of Class VI wells. } 

Response: EPA agrees that many Class I, Class II, and Class V experimental technology wells are

designed and constructed to withstand exposure to CO2. The final GS rule provides for the

construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can

demonstrate to the Director that the wells were engineered and constructed to meet the requirements

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

§146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other

Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met

following a determination under §146.81(c).

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22544

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: Classification of Injection Wells for Carbon Sequestration, Class II Injection 

Well Transition, and Grandfathering 

The EPA published a guidance document in March of 2007 recommending that the 

geologic sequestration experimental projects during this period of research use 

the Class V experimental category for classification of the injection wells 

(Using the Class V Experimental Technology Well Classification for Pilot 

Geologic Sequestration Projects - EPA 2007). These projects are currently 

underway at the Department of Energy’s (DOE’s) National Energy Technology 

Laboratory Regional Partnership test sites. Thus, there will be a need in the 

future for a regulatory mechanism for transition of these Class V experimental 

wells to Class VI operational status. There are also a number of Class II 
enhanced oil recovery (EOR) wells that have been used for testing of the 

sequestration process. These wells, too, may need a mechanism for transition to 

Class VI for operational use. 

Response: EPA agrees that many Class II and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule provides for the construction of

these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to

the Director that the wells were engineered and constructed to meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA does not believe that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the well as Class VI, many

of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22545

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment); 3130 2.1.3 Comments that operators should submit more (or different)

geologic data than proposed; 4710 2.7.1 Proposed submissions required for permit applications

(seeking comment) 

Comment: The NGWA Carbon Sequestration Task Force recommends that the experimental phase 

extend beyond the regional partnerships to each site proposed for productionscale injection of carbon dioxide. It is recommended that at least one well at 

each site be constructed under the Class V experimental category, and that 

testing of the adequacy of the geologic environment for geologic sequestration 

of carbon dioxide be conducted prior to permitting any well in the Class VI 

category at the site. 

The transition of carbon dioxide injection wells from Class II (Enhanced Oil 

Recovery wells) to Class VI (carbon sequestration wells) will presumably be 

requested when production of the petroleum has ceased. Liquid carbon dioxide 

from a distant source, such as a power plant, can be stored in the depleted 

petroleum reservoir even after production has ceased, necessitating a change in 

classification of the injection well. The new use of the wells involves much 

longer storage time, and raises concerns about mechanical integrity and long 

term effects, including geochemical changes, on underground source of drinking 

water (USDWs). The reclassification should depend on a positive outcome from a 

Class V experimental program conducted in the depleted reservoir, as described 

below. 

The "grandfathering" of Class V carbon sequestration wells would mean allowing 

experimental wells to be permitted for operation after the testing period is 

over. The NGWA Carbon Sequestration Task Force recommends that each carbon 
sequestration system or wellfield have an experimental phase, and not rely on 

results from distant experimental locations. Thus, nearly every operational 

well would start as a Class V experimental well, or would go through a Class VI 

testing phase, before being permitted for long-term operation. The transition 

to Class VI operational status would require demonstrating that the minimum 

requirements are met at that location. Most wells would go through the 

following permitting phases: 

- Class V experimental well construction permit: This permit would allow 

geologic and geophysical testing, aquifer testing, laboratory work, etc, but 

would not include injection of CO2 (only potable water injection testing would 

be allowed). 

- Class VI experimental well operational testing permit: At this stage, 

the full monitoring facilities would need to be constructed. This permit would 

allow test injection of liquid CO2 at rates high enough to demonstrate that the 

location meets the minimum requirements for operation, for a period of up to two 

years. 

- Class VI operation permit: After demonstrating that the location and 

the well meet all the minimum requirements for injection of CO2, the operation 

permit can be issued. 

The goals of the experimental well Class V construction permit would be to make 

the following demonstrations: 

- A receiving zone of sufficient depth, area extent, thickness, porosity, and 

permeability is present; 

- Lithologic description, geological name, thickness and depth of each confining 

unit above the storage aquifer, and of each USDW. 

- A trapping mechanism that is free of pathways for migration of injected fluids 

into a USDW. These pathways may include major non-sealing faults, porous beds 

within the confining unit, changes of facies trending toward more porous units 

and man-made structures such as wells or mine shafts. A trapping mechanism is 

defined as a geologic environment that prevents vertical and horizontal movement 

of fluids into a USDW; The volume of the trap shall exceed the proposed total 

volume of injected carbon dioxide for the life of the proposed facility 

- Identification of all confining units between the primary injection/storage 

zone and the lowermost USDW, and their adequacy to contain the injected fluid. 

Unless the only feasible injection zone has only one confining unit separating 

it from the lowermost USDW, this demonstration includes adequacy of confinement 

for both the primary confining unit and a secondary containment system that 

extends to the base of the lowermost USDW and is completely redundant of the 

primary confining system and could confine the injected CO2 should the primary 

system fail. In locations where the secondary containment system is not 

possible, the applicant shall propose an alternative system of early warning of 

failure of the primary confining unit in order to avoid impacting any USDW 
should that confinement fail. This demonstration applies in the horizontal 

sense as well, demonstrating one or more mechanisms containing the fluid from 

horizontal movement into a USDW in the storage aquifer at a distant location. 

- The construction of an operational monitoring system meeting all the 

requirements described in this document’s MMV section, and demonstration of the 

adequacy of this system to meet those requirements. 

- Demonstration of mechanical integrity 

Having made the foregoing demonstrations, a Class VI operational testing permit 

can be issued for a period of up to two years. The goals of the experimental 

well Class VI operational testing permit would be to make the following 

demonstrations: 

- A hydraulic demonstration of the adequacy (depth, area extent, thickness, 

porosity, and permeability) of the storage zone, using monitoring data and 4-D 

seismic monitoring of the extent of the CO2 plume. 

- Demonstration of the adequacy of the trap for 5/10 years of injection at the 

proposed rate. The volume of the trap shall exceed the proposed total volume of 

injected carbon dioxide for the 5/10 years of the first operation permit. 

- Demonstration of the adequacy of confinement under operational conditions 

using monitoring data and a method of detecting the extent of the CO2 plume in 

the storage aquifer, such as 4-D seismic monitoring or direct sampling. 

- Re- evaluation of the Area of Review and extent of the zone of endangering 

influence. 

- Re-evaluation of mechanical integrity, using the buoyancy of the injected CO2 

to better measure external mechanical integrity. The re-evaluation shall 

include the testing required during the initial MIT, as well as evaluation of 

the cement for carbonation, or chemical weathering by CO2 

Under this permitting scenario, the vast majority of Class V experimental wells 

would be constructed after the Class VI standards had been published. The 

"grandfathering" of Class V wells that do not meet the Class VI construction 

standards would only be needed for DOE test sites established before rulemaking 

was complete. If these wells include the ongoing mechanical integrity 

monitoring of annular fluid pressure and composition, and they pass periodic 

mechanical integrity testing, they should be able to follow the same permitting 

procedures to become operational Class VI wells. 

Response: EPA believes that submittal and review of monitoring data (as required at §146.90) and

the AoR reevaluation process (§146.84(e)) will provide an opportunity for an ongoing review of the

site and a dialogue between the Director and the owner or operator to ensure that the project is being

operated in a manner that protects USDWs from endangerment. EPA notes that changes to these

plans require a permit modification under §144.39, the public must be notified according to the

public comment procedures under 40 CFR 124.

Please see the final rule and the discussion of geologic site characterization in the preamble for

additional information.
EPA disagrees that every GS well should initially be permitted as a Class V well. The Agency

believes that the tailored Class VI requirements including extensive requirements for geologic site

characterization at §146.82, AoR evaluation at §146.84, and testing of the well during drilling at

§146.87 are appropriate to ensure that permitting authorities have the necessary information to

evaluate whether a specific site will allow safe injection of CO2. EPA adds that submittal and review

of monitoring data (as required at §146.90) and the AoR reevaluation process (§146.84(e)) will

provide an opportunity for an ongoing review of the site and a dialogue between the Director and

the owner or operator to ensure that the project is being operated in a manner that protects USDWs

from endangerment. Given this approach to permitting Class VI projects, EPA believes that the

requirements for grandfathering of construction at §146.81(c) are necessary and appropriate.

Commenter Name: Patrick Nugent Letter ID: 0143

Commenter Organization: Texas Pipeline Association (TPA) Comment ID: 23144

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: 11. Grandfathering of well construction standards for Class II and Class V 

wells should be provided without condition. EPA proposes to grandfather the well 

construction standards for a Class II and a Class V well that is converted to a 

Class VI well and requests comments on how this proposal may affect compliance 

with the proposed well construction standards for Class VI wells. TPA believes 

that the construction standards for an existing Class II or V well that is 

converted to a Class VI well should be accepted by EPA as having met the Class 

VI well construction requirements. The meaning of "grandfathering" an 

environmental requirement is just that: the requirements in place at the time 

continue to apply. If this were not the case, a viable sequestration project may 

not occur as development of a new well may be cost prohibitive. 

Response: EPA agrees that many Class II and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule provides for the construction of

these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to

the Director that the wells were engineered and constructed to meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the well as Class VI, many

of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

Commenter Name: Sandi Tabor Letter ID: 0162

Commenter Organization: Lignite Energy Council (LEC) Comment ID: 21299

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: regulated under the Class II program. For that matter, we also support granting 
state UIC directors the authority to grandfather the construction requirements 

for Class II and V wells when they are converted to full scale Class VI wells. 

Response: EPA agrees that many Class II and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule provides that the construction of

these wells be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the

Director that the wells were engineered and constructed to meet the requirements at §146.86(a) and

ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies

that only the construction requirements are grandfathered and that all other Class VI requirements

(reporting, monitoring, mechnical integrity testing, etc.) must be met following a determination

under §146.81(c).

Commenter Name: Michael Mudd Letter ID: 0167

Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 22456

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: Impact on Class II and Class V Wells p.43502, c. 1 

The Proposed Rule for Class VI wells should have no impact on existing or future 

Class II or Class V wells, which should be stated in the Proposed Rule in clear, 

unambiguous, and strong language. Furthermore, the Proposed Rule allows for the 

construction of existing Class II and Class V wells to be grandfathered, but 

there is no provision to allow the grandfathering of the existing siting, area 

of review, operations, or monitoring plan. These areas should be grandfathered, 

too. 

Response: EPA agrees that many Class II and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule provides for the construction of

these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to

the Director that the wells were engineered and constructed to meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR

requirements) should also be grandfathered. Following re-permitting of the well as Class VI, many

of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk

profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting

as Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting,

plugging, and post-injection site care and site closure requirements in the final GS rule. See the

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on

these requirements.

Commenter Name: James Rower Letter ID: 0173

Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23477

Other EPA Comment Codes and Descriptions: 2062 1.5.3.1 Grandfathering construction of Class

I wells (seeking comment) 

Comment: 4. Grandfathering Requirements for Class I and V UIC Wells 
Grandfathering is an extremely important issue to USWAG as a number of our 

members have invested substantial resources in developing and permitting 

nonhazardous Class I and V experimental CO2 injection wells to help demonstrate 

the viability of large-scale commercial deployment of CO2 sequestration. Federal 

and state governments are encouraging these efforts as their success is critical 

to the large-scale commercial deployment of CO2 sequestration. Therefore, Owners 

or Operators should be given the opportunity to operate these wells on a regular 

basis as Class VI wells once the wells have been shown to be safe and effective 

on an experimental basis. This will help encourage the substantial upfront 

investment necessary to get these wells permitted. USWAG therefore supports the 

Proposal's provision allowing for the grandfathering of construction 

requirements for existing Class I and V wells developed for the injection of CO2 

if and when Owners or Operators of those wells seek a Class VI permit for GS of 

CO2. Id. at 43502. 

Response: EPA agrees that many Class I and Class V experimental technology wells are designed

and constructed to withstand exposure to CO2. The final GS rule provides for the construction of

these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to

the Director that the wells were engineered and constructed to meet the requirements at §146.86(a)

and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA

clarifies that only the construction requirements are grandfathered and that all other Class VI

requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met following a

determination under §146.81(c).

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25174

Comment: D. Accordingly, EPA is proposing that the Director have the discretion to 

"grandfather" the construction requirements for Class V experimental wells 

when they are converted to full-scale GS Class VI wells. As with converted Class 

I and Class II wells, these grandfathered wells would be required to meet the 

other requirements of today’s proposed rule (e.g., operating, monitoring, MIT, 

well plugging, post-injection site care and site closure). 

NYSDEC-DMN Response: NYSDEC-DMN agrees that this discretion is appropriate and 

necessary when reviewing other UIC Class wells for use as UIC Class VI wells. 

Response: EPA agrees that many Class V experimental technology wells are designed and

constructed to withstand exposure to CO2. The final GS rule provides for the construction of these

wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the

Director that the wells were engineered and constructed to meet the requirements at §146.86(a) and

ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies

that only the construction requirements are grandfathered and that all other Class VI requirements

(reporting, monitoring, mechnical integrity testing, etc.) must be met following a determination

under §146.81(c). 

Commenter Name: Paul Pike Letter ID: 0198

Commenter Organization: Ameren Corporation Comment ID: 23942
Comment: GRANDFATHERING 

Ameren and many other companies are participating in the DOE Regional Carbon 

Sequestration Partnerships as well as individual projects and believe that it is 

important that wells developed solely for the purpose of demonstrating the 

viability of CO2 sequestration should be grandfathered into the Class VI 

program. This means that regardless of the original permitting status of the 

well, it can be eventually transition to Class VI. These "demonstration" wells 

may have included requirements valuable to understand the process, but 

unnecessary for a routinely operated facility and those could be dropped in the 

transition. If necessary, the Director could identify why continued operation 

of the well necessitates additional requirements which the permitee would be 

allowed the opportunity to respond. 

Response: EPA agrees that, when the Regional Carbon Sequestration Partnership projects are no

longer of an experimental nature, they should be re-permitted as Class VI wells and subject to the

Class VI requirements if they are to be used for commercial-scale GS.

EPA is providing for the construction of Class V experimental technology wells to be grandfathered

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

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

in lieu of requirements at §146.86(b) and §146.87(a). EPA understands based on reviews of several

Class V pilot project permits, that many Class V experimental technology wells, including those used

in the RCSP projects, are specifically designed for injection of CO2 and are being built to Class I

non-hazardous well specifications, which should facilitate re-permitting as Class VI wells. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies.

Commenter Name: Jonathon Palm Letter ID: 0222

Commenter Organization: Nevada Division of Environmental Protection, Bureau

of Water Pollution Control

Comment ID:

21642

Other EPA Comment Codes and Descriptions: 2064 1.5.3.2 Grandfathering construction of Class

II wells (seeking comment) 

Comment: 3. Existing Class II & V wells should not be grandfathered in on long-term CO2 

injection projects. Injection into a Class II oil well may be appropriate for 

short-term project in a producing oil/gas field, but CO2 injection will outlast 

a producing field and may not have been constructed to specs. All CO2 wells must 

be specifically designed. 

Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given

that the converted well will be used for a substantially different process, which involves increased

reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the

presence of water. The final GS rule provides for the construction of these wells to be grandfathered,

per §146.81(c). EPA has included a requirement in the final GS rule that owners or operators

seeking to convert existing wells for long term storage must demonstrate to the Director that the

grandfathered wells were engineered and constructed meet the requirements at §146.86(a) and ensure
protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies that only

the construction requirements are grandfathered and that all other Class VI requirements (reporting,

monitoring, mechnical integrity testing, etc.) must be met following a determination under

§146.81(c).

Commenter Name: Andrew Duguid Letter ID: 0226

Commenter Organization: Schlumberger Carbon Services Comment ID: 24007

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: §144.15 Prohibition of non-experimental Class V wells for geologic 

sequestration. 

Proposed Rule: The construction, operation or maintenance of any nonexperimental Class V geologic sequestration well is prohibited. 

Schlumberger Suggested Revision: - 

Schlumberger Rationale: We agree, there should be only one class of geologic 

sequestration well but CO2 class V wells should be grandfathered. 

Response: EPA agrees that many Class V experimental technology wells are designed and

constructed to withstand exposure to CO2. The final GS rule provides for the construction of these

wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the

Director that the wells were engineered and constructed to meet the requirements at §146.86(a) and

ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies

that only the construction requirements are grandfathered and that all other Class VI requirements

(reporting, monitoring, mechnical integrity testing, etc.) must be met following a determination

under §146.81(c). 

Commenter Name: Neeraj Gupta Letter ID: 0229

Commenter Organization: Battelle Energy Technology (BET) Comment ID: 21814

Comment: Page 48 "Grandfather" Status - It is unclear how this would affect existing 

MRCSP Phase II Test sites. These host sites have been very accommodating in 

supporting these small scale tests and it is unclear if they would be subject to 

long term monitoring or allowed to be closed out under the original Class V CO2 

experimental policy the wells were permitted under. Clarification that the 

small scale tests would be allowed to continue injection under their original 

permit conditions be closed out under their original permits would be helpful to 

the pioneers of this technology, unless of course the site hosts wish to convert 

to a Class VI well under new regulations for longer-term.. 

Response: EPA agrees that, when the Regional Carbon Sequestration Partnership projects are no

longer of an experimental nature, they should be re-permitted as Class VI wells and subject to the

Class VI requirements if they are to be used for commercial-scale GS.

EPA is providing for the construction of Class V experimental technology wells to be grandfathered

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

engineered and constructed to meet the requirements at §146.86(a) and ensure protection of USDWs,
in lieu of requirements at §146.86(b) and §146.87(a). EPA understands based on reviews of several

Class V pilot project permits, that many Class V experimental technology wells, including those used

in the RCSP projects, are specifically designed for injection of CO2 and are being built to Class I

non-hazardous well specifications, which should facilitate re-permitting as Class VI wells. EPA adds

that, following re-permitting as Class VI wells, these projects must be subject to the operational,

MIT, monitoring, reporting, plugging, and post-injection site care and site closure requirements in

the final GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS

rule for additional detail on these requirements.

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies.