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 inclu des 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 code s 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 20481.5.3 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 §146.82require 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 storedfor 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 oiland 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 ofCO2 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.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 fluidswithin 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 throughInjection" (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 islikely 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: 0215Commenter 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, orroughly 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 athttp://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 termstorage. 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 raisedby 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 finalizationof 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.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 solesource 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, salinereservoirs; 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. Forexample, 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 additionalzones, 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 LetterID: 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,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,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 traceelements 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 inprogress. 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,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 toaddress 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 hasconducted 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 requirementsunder §146.90, including proposed monitoring plans. The guidance describes available technologiesand 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 InSalah, 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 toaddress 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 hasconducted 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 oneproject, 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 technologiesand 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 Vexperimental 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 athttp://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 ProjectsGlobally, 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,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 TechnologyLaboratory (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 currentlyunderway, 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 proposedrule assists with creating additional certainty in approaching GS projectdevelopment, 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 isnot 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 Fieldproject 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 fielddemonstrations 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 ofthe 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.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’sNational 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 differentlocations 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.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 andgranting 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

### 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: 0114Commenter 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,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 legislationand/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.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 apermit 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 onspecific 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) andthe 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: 23050Other 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." Thisapproach 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 EPAmanagers 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.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 theowner 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: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: 0116Commenter 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 ofCO2 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 newtechnology, 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 theGS 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 gasconsisting 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[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 expertiseand 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 OversightRegional 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 storageprogram 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.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 injectingthe 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 integralpart 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 theothers 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 theprimary 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 belowthe injection zone used for geologic sequestration.

Response: As described above regarding the suggested edit at 144.6(b), EPA did not make thesuggested 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 thesuggested 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 preventingendangerment 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 behelpful 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 tailoredspecifically 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: 24833Comment: 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 geologicsettings 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 correctiveaction, 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 non traditional 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 wellsare 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 advisesResponse: 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 projectsthat 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 rulemakingComment: 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 geologicsequestration, 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: 23535Other 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 injectionof 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 ofResponse: 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 injectionfor 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 forthe 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 performance based 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 unlikelyevent 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 existingUIC 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 testingand 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 oilfield 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 resourcesnecessary 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 regulatedunder 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 anincreased 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: 0148Commenter 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 isalso more likely to provide storage site operators with the financial resourcesnecessary 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. TheDirector 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, withClass 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 wellclassification 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 GSComment: 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 wellsare 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 atmaximum), 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 injectionwell, 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 projectsthat 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 IIwhere 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 forthe 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 primarypurpose 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 IIwhere 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, long standing 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 IIwhere 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 ifEPA'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

INCREASEEXTRACTION 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 inWyoming, 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 GASPROVIDED (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 thesuggested 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 thesuggested 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 INCONNECTION 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 thesuggested 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 otherClass 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 seethe 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 IIwhere 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 betweenUSDWs 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 IIwhere 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 Energystudied 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 IIwhere 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: 23683Comment: 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 USDWsand 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 IIwhere 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 IIwhere 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 IIwhere 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 furtherdetail 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 primarypurpose 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, EPAshould 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 GSoccur 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 aUSDW. 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 thesuggested 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, wellconstruction 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 IIcontext) 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 correctlyrecognizes, 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 IIwhere 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-stakeholderdiscussion (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, unlessthose 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 ClassII 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) operatingpressures 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 thepreamble 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 seethe 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 andoperation, 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: 146.5Anadarko 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 ANINJECTION 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 allowthe 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 geologicsequestration, 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-authorizedClass 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 IIwhere 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 flexibilityas 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 IIwhere 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 IIwhere 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 factorfor 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 toaddress 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 IIwhere 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 salineformations 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 andunmineable 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 gasproduction 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 amountsof 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, therebypotentially 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 associatedwith 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 business as-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 primarypurpose 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 createthis 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-as usual 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:

21575Comment: 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 infrastructureexist 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, post injection 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 IIwhere 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, GSis 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 criticalthat 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 ClimateChange ("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 acknowledgein 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 IIwhere 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 criticalthat 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 ClimateChange ("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 occursduring 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 gasformations 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 IIwhere 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 GSsites. 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 IIwhere 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 ClassVI 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 Agencywill 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 estimatedthat 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 primarypurpose 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 IIwhere 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 ofinformation 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 thatrationale 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 gasrecovery 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 IIwhere 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 searchfor 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 addressedunder 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 otherstates, 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 inparagraph (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/EGR related 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-O3 07.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 IIwhere 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 IIwhere 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 IIwhere 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 whileallowing 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 theEPA'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 reviewedand 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 IIwhere 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 gasindustry 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 factthat 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 IIwhere 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 toClass 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 redlinestrikeout 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 abandonedwells 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 ata 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 anyother 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 cementedto 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 setforth 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 submitto 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 shorternotice 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 thedesignated 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 ofreview 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 hydrocarbonreservoirs 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 andcorrective 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 IIwhere 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 thatUIC 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 IIwhere 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, theproposed 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 onlygeologic 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 todistinguish 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. TheDirector 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 IIwhere 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 USDWswhen 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 carboncapture 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 itstays 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 USDWsand 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: 24368Comment: 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 experimentaltechnology 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, coalseams, 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 144.15provision 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 CommentsCommenter 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 currentlyconducted 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 geologicformations. (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 giventhat 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 reevaluationprocess (§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 theseresearch 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 tobecome 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). EPAclarifies 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 thefinal 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 thepurpose 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 experimentaltechnology 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 ClassII 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 ruleaffords 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:

25187Other 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 ensureprotection 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 thatthe 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. Thesewells 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 theconstruction 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 bemet 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 tobecome 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 VIwells. 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) ensurethat 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 thisconversion 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 GSsites (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 ClassII 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 theCCGS 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 thediscussion 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 Iand 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 thisdetermination, 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 increasedreservoir 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 notendanger 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 useof 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: 0504Commenter 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 closurerequirements 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 addsthat 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 productionceases. 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 ofpore 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 geologicformations. (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 WellsGrandfathering is an extremely important issue to USWAG as a number of our members have invested substantial resources in developing and permitting

non hazardous 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: 0238Commenter 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 usinganthropogenic 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 anincreased 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 thestandards 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 geologicformations. (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 metfollowing 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: 0142Commenter 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 phaseextend 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 unitsand 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 rulemakingwas 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 aredesigned 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 determinationunder §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, theseprojects 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 APIhad 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 thesuggested 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. TheDirector 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 endangera 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 thehandling 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 StorageAfter 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 CO2sequestration 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 estimatedthat 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 suchprojects - 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 existingClass 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 IIwhere 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 onthese 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: 0506Commenter 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 ifanthropogenic 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 havegot 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: 0122Commenter 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 geologicformations. (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 IIenhanced 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 phaseextend 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 carbonsequestration 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 USDWshould 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 grantingstate 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 WellsGrandfathering is an extremely important issue to USWAG as a number of our members have invested substantial resources in developing and permitting

non hazardous 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: 23942Comment: 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 ensureprotection 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.