### This comment letter response contains two parts:

(1) The original submittal from the commenter. (2) A data base printout of EPA’s response to each point raised by the commenter.

Notes about the response letters:

• The response letters were generated by a data base used to track the content of all public

comment submittals and ensure that the Agency responds to each. Each comment letter

was assigned a Letter ID that corresponds to the last four digits of the docket number of the original comment (as posted on www.regulations.gov).

• Each response letter includes: comment text; an EPA

‐ assigned comment code; and an
individual response. These are described and explained below.

• The data base contains Comment text from the letters submitted by commenters.
Many hard copy letters were scanned into electronic format for inclusion in the data

base. As a result, there may be some typographical errors attributable to optical

character recognition issues. However, all original submittals were reviewed in the

process of drafting responses to ensure that the comment content was understood and appropriately addressed.

• The content of each comment letter was divided into topic areas and assigned a unique

Comment ID. Additionally, one or more Comment Codes (i.e., unique topic area ID) was assigned to each discrete point raised by a commenter. This information was added to

the data base. To inform final rulemaking decisions, all comments and information

received on a given topic were reviewed by technical experts in each rule area (e.g., on

construction requirements).

• Following decisions on the final rule requirements, Individual responses were drafted
by topic area to ensure completeness and consistency of the responses with the final

rule and other responses to similar comments. Each discrete point made by a

commenter was given a unique response.

• Upon completion of comment responses, all information was entered into the data base.

Each letter response is a compilation of each comment and its individual response, compiled in the order of the original comment letter. As a result of this process, there is
repetition in the response text. The Agency believes this approach ensures completeness

and attention to each comment letter that was submitted.

• All comments in a topic area were reviewed, evaluated, and responded to concurrently.

Responses on each topic area are compiled and are also available in the rulemaking docket.

### BASIN ELECTRIC
POWER COOPERATIVE

1717 EAST INTERSTATE AVENUE BISMARCK, NORTH DAKOTA 58503-0564

PHONE 701-223-0441

FAX: 701/224-5336

December 18, 2008

VIA: E-MAIL 

### & FIRST CLASS DELIVERY

Stephen 

### L. Johnson, Administrator
U.S. Environmental Agency

Water Docket

Environmental Protection Agency

Mailcode: 2822T

1200 Pennsylvania Avenue NW Washington, DC 20460

Re: Basin Electric Power Cooperative/Comments

Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon

Dioxide (C0 2 ) Geologic Sequestration (GS) Wells

Federal Register/July 25, 2008

Dear Administrator Johnson:

Basin Electric Power Cooperative (Basin Electric) appreciates this opportunity to submit comments

to the Environmental Protection Agency (EPA) in regards to the proposed rule for Federal Requirements for the Underground Injection Control (UIC) Programs for Carbon Dioxide (C0 2 ) Geologic Sequestration (GS) Wells.



### I. Importance of Carbon Capture and Storate to Basin Electric and its Members:

Basin Electric is a regional, consumer-owned, power supplier formed in 1961 to provide supplemental power to a consortium of electric distribution cooperatives. Basin Electric's

core business is generating and delivering electricity to wholesale customers, primarily our member systems. Basin Electric owns 2,599 megawatts (MW) and operates 3,518 MW of

electric generating capacity. Basin Electric supplies 126 rural electric member cooperative systems with wholesale electric power who in turn serve approximately 2.6 million

consumers in a nine-state area.

Basin Electric has extensive institutional knowledge of coal gasification, carbon capture
and CO 2 sequestration through its subsidiary, the Dakota Gasification Company (DGC).

DGC owns and operates the Great Plains Synfuels Plant (Synfuels Plant), the only

commercial-scale coal gasification plant in the United States that manufactures synthetic natural gas.

The $2.1 billion plant began operating in 1984. The Synfuels Plant uses the Lurgi gasification process to gasify lignite coal to produce valuable gases and liquids. The

average daily production is 160 million standard cubic feet of synthetic natural gas (SNG),

the majority of which is piped to Ventura, Iowa, for distribution in the eastern United States. Many by-products and alternate products are produced and marketed in the United

States and worldwide.

DGC captures CO 2 from the gasification process and provides all the CO 2 sequestered in

the largest anthropogenic CO 2 sequestration project in the world. Through 2008, Dakota

A Touchstone Energy" Cooperative

## ~T~


# - Equal Employment Opportunity EmployerStephen 

### L. Johnson

December 18, 2008 Page 

### 2

Gasification has successfully captured and marketed over 13 million tons of carbon dioxide

to two Canadian customers. The current total carbon dioxide demand is 152.7 million

standard cubic feet (MMscf), which is approximately 8,800 tons per day or 3 million tons per

year. The CO 2 is being used for enhanced oil recovery (EOR) in oil fields near Weyburn,

Saskatchewan. The CO 2 is expected to be permanently sequestered in the oil reservoir and

is being monitored by the International Energy Agency (lEA) Weyburn CO 2 Monitoring and Storage Project. The 2000-2004 lEA GHG Weyburn CO 2 Monitoring & Storage Project Summary Report states in the Conclusion that "modeling predicts that there is a 95% probability that 98.7% to 99.5% of the initial CO 2 -in-place will remain in the geosphere for
5,000 years."

Basin Electric is also developing and attempting to move forward with a post-combustion

CO 2 capture demonstration project for a 120 megawatt slipstream of flue gas at its Antelope Valley Station (AVS), a pulverized coal power plant next to the DGC facility near Beulah,

North Dakota. If completed, this will become the largest demonstration of CO 2 capture on a conventional pulverized coal power plant. As NRECA notes in its comments, "Eighty
percent of the electric power generating plants owned by cooperatives, approximately
24,000 MWs, is coal-fired generation." So the development of post-combustion CO 2 capture

and sequestration (CCS) technology is an important step in allowing our nation's fleet of

conventional pulverized coal combustion facilities to remain a part of our nation's energy future in a world that will likely be COremission constrained.

The IPCC's 2005 report on "Carbon Capture and Storage" notes that mature sedimentary

basins such as the Williston Basin in the upper Great Plains are "prime targets for CO 2 storage because: (1) they have well-known characteristics; (2) hydrocarbon pools and/or

coal beds have been discovered and produced; (3) some petroleum reservoirs might be already depleted, nearing depletion or abandoned as uneconomic without advanced production systems such as EOR: (4) the infrastructure needed for CO 2 transport and injection may already be in place.,,1 Use of CO 2 for EOR often adds an additional 7-23% of

incremental oil recovery from a field, and depleted oil fields have advantages for CO 2 sequestration because "the oil and gas that originally accumulated in traps (structural and stratigraphic) did not escape (in some cases for many millions of years), demonstrating their integrity and safety," and because "the geological structure and physical properties of most

oil and gas fields have been extensively studied and characterized.,,2 IPCC's 2005 "Carbon Capture and Storage" Report also recognizes that Basin Electric's DGClWeyburn project, "despite the presence of many hundreds of existing wells, after four years of CO 2 injection

there has been no measurable leakage (Strutt et al., 2003)."3 Thus, EOR is an established option for CO 2 sequestration in the Williston Basin, and geological formations are holding sequestered CO 2 without leakage. There is an identified need for additional CO 2 for EOR in

the Williston Basin when the technology becomes mature enough to provide it at a reasonable cost to customers. Basin Electric's AVS Post-Combustion CO 2 Capture Project

is an attempt to move that technology forward.

In addition to EOR options, saline aquifers have been identified in the Mississippian

Madison geological formation of the Williston Basin with the capacity to store approximately

1 IPCC "Carbon Capture and Storage" Report (2005), Chapter 5, p. 215, available at http://www.ipcc.ch/ipccreports/srcc.htm.

2 1d

.

3 1d

.Stephen L. Johnson

December 18, 2008 Page 3

60 gigatons (i.e., 60 billion tons) of CO 2 , which is enough capacity, for example, to store all

of the CO 2 emitted from a facility emitting 3 million tons of CO 2 per year for 20,000 years.

IPCC's 2005 report on "Carbon Capture and Storage" also says that most scenarios project

that the supply of primary energy used by humans will continue to be dominated by fossil

fuels until the middle of the 21 SI -century.4 The IPCC notes that stabilizing CO 2 levels in the atmosphere will not likely be achieved with a single technological option, but CO 2 capture

and storage (CCS) in geological formations is one of the most important technologies that

may make such stabilization possible.,,5

"[T]he global capacity to store CO 2 deep underground is large. Depleted oil and gas reservoirs are estimated to have a storage capacity of 675-900 [metric gigatons of] CO 2

. Deep saline formations are very likely to have a storage capacity of at least 1000 [metric gigatons of] CO 2 and some studies suggest it may be an order of magnitude greater than this, but quantification of the upper range is difficult until additional studies are undertaken." 6

The IPCC "Carbon Capture and Storage" Report acknowledges that natural underground

accumulation of CO 2 is "a widespread geological phenomenon," and that '[w]hile there are differences between natural accumulations and engineered storage, injecting CO 2 into deep geological formations at carefully selected sites can store it underground for long periods of

time: it is considered likely that 99% or more of the injected C02 will be retained for 1000 years."?

Geological sequestration of CO 2 is, in sum, one of the important tools available for stabilizing
CO 2 levels in the atmosphere, and Basin Electric/DGC's Weyburn project is currently the largest carbon sequestration project in the world demonstrating the feasibility of such
capture and storage. Whatever steps are taken either legislatively or through rulemaking to regulate CO 2 and other greenhouse gases (GHGs) must allow CCS technology and other

carbon and GHG control technologies to be developed, and must allow a reasonable time

frame to do so.



### II. Importance of Developing Reasonable Regulations

The energy needs of the United States are dependent upon carbon producing fuels. The development of reasonable regulations, including reasonable regulations for carbon dioxide capture and sequestration (CCS), thus is crucial for CCS is to fulfill its potential as one of the important ways to mitigate greenhouse gas impacts. "While other climate mitigation options

exist-such as energy efficiency improvements, a switch to less carbon-intensive fuels,

nuclear power, and renewable energy sources-CCS is considered by many to be a crucial
component of any U.S. approach or strategy for addressing the climate change problem, particularly given the United States' current reliance on coal for almost half of its electricity production." 8

4 Id. at p. 3.

5 Id. at p.53.

6 Id. at p. 197.

7 Id. at 

### p. 197.

8 GAO, Federal Actions Will Greatly Affect the Viability 

### of Carbon Capture and Storage As 

### a Key Mitigation Option, GAO-08-1080 at 1 (Washington, D.C. September 30,2008).Stephen 

### L. Johnson

December 18, 2008 Page 4

The use of carbon dioxide for enhanced oil recovery (EOR) is also generally recognized as

an important intermediate step in developing EOR, because the knowledge and technology

is already there to begin to use it. "The injection of CO 2 in deep geological formations

involves many of the same technologies that have been developed in the oil and gas exploration and production industry. Well-drilling technology, injection technology, computer

simulation of storage reservoir dynamics and monitoring methods from eXisting applications

are being developed further for design and operation of geological storage."g



### III. General Comments

EPA must be careful to avoid labeling sequestered CO 2 as a waste, pollutant or contaminant. Regulations should require storage operators to properly characterize the CO 2 they intend to store and protocols for storage should be based on that characterization.

Broad sweeping characterizations of sequestered CO 2 as hazardous waste, however,

should be avoided due to the potential deterrent such characterizations will have on entities attempting to develop carbon capture and sequestration 

### (CCS) projects.



### IV. Comments on Identified Issues

The following comments are directed to the specific questions raised in the proposed rule.



### "3. Tracking the Results of CO 2 GS 

### Research Projects"

The EPA states,"4-D seismic monitoring may be a valuable tool for CO 2 plume tracking."

The emphasis on "may be" reflects the fact that there are a variety of monitoring tools

available and also a variety of site-specific geologic conditions thus the tools used to track

the location of the CO 2 plume should be flexible, and the regulations should reflect this flexibility in choosing methods. "4-0 seismic monitoring" has been demonstrated as a research tool but may not be needed as a minimum operating tool. "4-0 seismic monitoring"

is an extremely expensive option. However, geochemical sampling methods and monitoring

wells can be used to determine the distribution of CO 2 within a reservoir and monitor for leakage.



### "G. How Would This Proposal Affect Existing Injection Wells Under the utC Program?"

EPA's approach to CO 2 injection in Class /I and Class V wells for EORlEGR as long as oil/gas production continues does not take into consideration the GS of CO 2 that takes place

from this process. CO 2 , atthe time of injection in Class /I and Class V wells for EORIEGR,

needs to be considered sequestered and in GS until production from the field is completed. Upon completion of the field, Class /I and Class V wells will be issued a GS permit and the

construction requirements needs to be grandfathered into the Class VI well classification.



### "H. What Are the Target Geological Formations for GS 

### of CO 2 

### ?''

Basin Electric urges the EPA to not arbitrarily exclude certain formations for the injection of

CO 2 • Rather, determination of appropriate geology for sequestration should be site specific.

9 IPCC "Carbon Capture and Storage" Report at p. 31.Stephen 

### L. Johnson

December 18, 2008 Page 5

Broad exclusions of geological formations would result in the non-utilization of large area of potential storage. In addition, exclusion of un-mineable coal seams would prevent the

recovery of potentially large quantities of natural gas.

State Directors should have the responsibility of determining whether or not injection into

coal seams, oil and gas formations, locations above the lowermost underground source of drinking water (USDW), etc. should be permissible. Rather than a broad exclusion, proper site selection, site characterization and engineering should be utilized in determining the suitability of a potential sequestration site.



### "I. Is Injected CO 2 

### Considered 

### a Hazardous Waste Under RCRA 

### ?

Under the proposal, EPA states that it cannot make a categorical determination as to
whether injected CO 2 is hazardous under RCRA. It suggests the burden should be on the operators to characterize their CO 2 stream as part of the permit application to determine if

the injectate is considered hazardous as defined in 40 CFR Part 261. RCRA regulates the production, management, and disposal of wastes and RCRA's potential application in the

case of CO 2 injectate is dependent upon the existence of a solid waste. If the material is a solid waste, the law requires further analysis to determine if it is also a hazardous waste.

Injected CO 2 should be considered a product or a commodity and not a solid waste. Leaving the question to be resolved when operators characterize their CO 2 streams with the potential that RCRA liability may attach will be a deterrent to CO 2 storage projects. Basin

Electric urges the EPA to make a determination under its RCRA authority the CCS activities meeting Class VI permit requirement do not equate discarding the CO 2 • By so doing, Class

VI CO 2 injection operations would not be considered waste management activities and

would not be subject to RCRA.

EPA should view CCS as a resource, not a waste. EPA should specifically exempt injected
CO 2 streams from coverage by RCRA and develop requirements tailored to this material if

necessary to ensure further environmental protection beyond that provided by the UIC permitting process.

As further justification for this position, simply consider the success of existing acid gas injection operations into depleted oil and gas reservoirs conducted under the existing protective UIC regulations. Impurities, such as H 2 S or mercaptans, should not trigger a classification under RCRA. The proposed rule has adequate protection for drinking water aquifers and addresses corrective action, financial assurance requirements, and long-term monitoring after closure. These requirements negate the need for any RCRA regulation.

Basin Electric wants to avoid open-ended and enhanced liabilities and risks resulting from requirements that do not significantly contribute to health and environmental protection.



### "J. Is Injected CO 2 

### Considered 

### a Hazardous Substance Under CERCLA 

### ?"

EPA seeks comment on whether Class VI permittees could be exempt from CERCLA under

its "federally permitted release" provision. First, liability under CERCLA depends on whether

there has been a disposal of hazardous substances. While CO 2 is not a CERCLAStephen 

### L. Johnson

December 18, 2008 Page 6

hazardous substance, EPA suggests in the preamble that the makeup of a particular injected CO 2 stream may trigger a CERCLA analysis. However, the preamble also states
that CERCLA's "federally permitted releases" provision exempts releases in compliance with

a UIC Permit under the Safe Drinking Water Act (SDWA) from CERCLA liability. This exemption in and of itself should put the issue to rest. EPA should make clear that this

exclusion provides a shield from Superfund liability. We urge the EPA to address the longterm liability for stored CO 2 within the UIC Class VI Well Permit. EPA should avoid creating

unnecessary hurdles for the successful deployment of CCS by assuming that potential applications of other statutes that may come into play.

Basin Electric requests that EPA recognizes that CO 2 injection and storage is exempt from
CERCLA liabilities and regulates this activity by compliance with the UIC Class VI Well

Permit. Also, please see previous comments on the exclusion of the injected CO 2 stream as

a hazardous waste (RCRA). If the UIC Program cannot coordinate these exclusions for

RCRA and CERCLA, BEPC requests that a legislative option be considered.

EPA should establish a single, clear, and reasonable regulatory structure for managing risks

and liabilities for CCS projects. The process to obtain a UIC Class VI Permit and defining

the Area of Review (AoR) will provide proper protections of the USDWS, environment, and

health.



### "1. Proposed Geologic Siting Requirements"

EPA requests comments on whether the final rule should require the identification and

characterization of additional confining and containment zones with the primary (lowermost) confining zone that could further impede vertical fluid movement and allow for pressure dissipation and act as a "secondary containment" requirement.

Basin Electric opposes the inclusion of this secondary containment or characterization requirement as a default provision. In the rare situation where specific site circumstances

would warrant, the State Director could exercise discretion and require this additional protection in a Class VI Permit.

This requirement for additional containment zones is not needed if it has already been

demonstrated and characterized that the original confinement zone is protective of USDW.

The requirement to identify and characterize additional zones that will impede vertical fluid

movement is too broad.



### "3. Proposed Injection Well Construction Requirements"

EPA seeks comments regarding degradation resistant well construction materials, such as acid resistant cements and corrosion resistant casing. Dakota Gasification and Basin

Electric agree with EPA's proposal to not specify materials and provide the owner/operator

the flexibility to choose materials within the appropriate construction standards. The owner/operator working with the State Director should be in the best position to determine a
cost effective strategy for construction, corrosion prevention, and corrosion monitoring that is

best suited for the site conditions. For example, Dakota Gasification's CO 2 pipeline and

much of the Weyburn field systems are constructed from carbon steel, even though this is

not common practice in acid gas systems. Due to some of the unique properties of this CO 2 stream, the corrosion issues have been insignificant after 9 years of continuous service.Stephen L. Johnson

December 18, 2008 Page 7



## "s. Proposed 

### Mechanical Integrity Testing Requirements"

The referenced annual tracer survey, temperature, or noise log is too burdensome and

should be changed to a five-year frequency or other criteria.



### "8. Proposed Well Plugging, Post-Injection Site Care, and Site Closure Requirements"

EPA is proposing to impose a 50-year post-injection site care (PISC) standard as the default

timeframe with the UIC State Director having the discretion to adjust this time period. Setting the tentative 50-year fixed timeframe that could be modified at the State Director's

discretion based on monitoring and modeling data does provide some flexibility. However,

Basin Electric urges the EPA to set the timeframe rules in an order that minimizes early risk projects and rewards early movers. The recently passed Emergency Economic Stabilization

bill that has become law (HR. 1428) provides in Division B sec. 115 tax incentives for

carbon dioxide sequestration either in secure geological storage or used as a tertiary injectant in a qualified enhanced oil or natural gas recovery project. It is imperative that the monitoring rules do not inhibit the ability of the Secretary of Treasury to give the credit to the appropriate taxpayer who has captured the carbon dioxide. Requiring 50 years of monitoring could preclude early commercial activity. The operator should be responsible for

the fixed timeframe of 10 years; however, provisions must be enacted for an eventual

transfer of liability and long-term monitoring to the government, most likely the state. The

Interstate Oil and Gas Commission 1 a-year recommendation was reviewed and rejected. However, since the State Director could modify the timeframe by extending the monitoring

time based on monitoring and modeling data, Basin Electric suggests lowering the fixed

timeframe to 10 years.

Thank you again for giving us the opportunity to file these comments.

Sincerely,

Claire M. Olson

General Counsel



### cmo/ds

### Letter ID: 0260

Commenter: Claire Olson Organization: Basin Elec tric Power Cooperative

Letter ID: 0260 Comment ID: 22384 Letter Lines: 94 to 144

Comment Code: 1000 1. General and Administrative Comments

Comment: The IPCC's 2005 report on "Carbon Capture and Storage" notes that mature sedimentary basins such as the Willist on Basin in the upper Great Plains are "prime targets for CO2 storage because: (1) they have well-known characteristics; (2) hydrocarbon pools and/or coal beds have been discovered and produced; (3) some petroleum reservoirs might be already depleted, nearing depletion or abandoned as uneconomic without advanced production systems such as EOR: (4) the infrastructure needed for CO 2 transport and injection may already be in place." [FN1] Use of CO2 for EOR often adds an additional 7-23% of incremental oil recovery from a field, and depleted o il fields have advantages for CO2 sequestration because "the oil and gas that originally accumulated in traps (structural and stratigraphic) did not es cape (in some cases for many millions of years), demonstrating their integrity and safety," and because "the geological structure and physic al properties of most o il and gas fields have been extensively studied and characterized ." [FN2] IPCC's 2005 "Carbon Capture and Storage" Report also rec ognizes that Basin Electric 's DGC/Weyburn project, "despite the presence of many hundreds of existing wells, after four years of CO2 injection there has been no measurable leakage (Strutt et al., 2003)."[FN3] Thus, EOR is an established option for CO2 sequestration in the Williston Basin, and geological formations are holding sequest ered CO2 without leakage. There is

an identified need for additional CO2 fo r EOR in the Williston Basin when the technology becomes mature enough to provi de it at a reasonable cost to

customers. Basin Electric's AVS Post-C ombustion CO2 Capture Project is an attempt to move that technology forward.

In addition to EOR options, saline aqui fers have been identified in the Mississippian Madison geological formati on of the Williston Basin with the capacity to store approximately 60 giga tons (i.e., 60 billion tons) of CO2, which is enough capacity, for example, to store all of the CO2 emitted from a facility emitting 3 million tons of CO2 per year for 20,000 years.

IPCC's 2005 report on "Carbon Capture and Storag e" also says that most scenarios project that the supply of primary energy used by humans will continue to be dominated by fossil fuels until the middle of the 21st-century.[FN4] The IPCC notes that stabilizing CO2 levels in the atmosphere will not likely be achieved with a single technologic al option, but CO2 capture and storage (CCS) in geological formations is one of the most important technologies that may make such stabilization possible" [FN5]

1

### "[T]he global capacity to st ore CO2 deep underground is la rge. Depleted oil and gas reservoirs are estimated to have a storage capacity of 675-900 [metric gigatons of] CO2. Deep saline formations are very likely to have a storage capacity of at least 1000 [metric gigatons of] CO2 and some studies suggest it may be an order of magnitude greater th an this, but quantific ation of the upper range is difficult until additional studies are undertaken."[FN6]

The IPCC "Carbon Capture and Storage" Report acknowledges that natural underground accumulation of CO2 is "a wi despread geological phenomenon," and that '[w]hile there are differences betw een natural accumulations and engineered storage, injecting CO2 into deep geologi cal formations at ca refully selected sites can store it underground for long peri ods of time: it is considered likely that 99% or more of the injected CO2 will be retained for 1000 years."[FN7]

Individual Response: EPA acknowledges the comment. EPA reviewed the IPCC report, as well

as more recent information on GS and Carbon Capture and Storage while developing the final

GS rule. Please see the remainder of EPA's res ponses to this letter fo r further details. For

additional information on EPA's fina l regulatory approach, please se e the final rule and preamble as well as the rulemaking docket.

Letter ID: 0260 Comment ID: 22385 Letter Lines: 146 to 175

Comment Code: 1330 1.1.3.1 Support use of GS in general

Comment: Geological sequestration of CO2 is, in sum, one of the important tools available for stabilizing CO2 levels in the atmos phere, and Basin Elec tric/DGC's Weyburn project is currently the largest carbon sequestration project in the world demonstrating the feasibility of such capture and stor age. Whatever steps are taken either legislatively or through rulemaking to regulate CO2 and other greenhouse gases (GHGs) must allow CCS technology and other carbon and GHG control technologies to be developed, and must allow a reasonable time frame to

do so.

II. Importance of Developing Reasonable Regulations

The energy needs of the United States ar e dependent upon carbon producing fuels. The development of reasonable regulations, including reasonable regulations for carbon dioxide capture and seque stration (CCS), thus is crucial for CCS is to fulfill its potential as one of the important ways to mitigate greenhouse gas impacts. "While other climate mitigation op tions exist-such as energy efficiency improvements, a switch to less carbon-i ntensive fuels, nuclear power, and renewable energy sources-CCS is considered by many to be a crucial component of any U.S. approach or strategy for ad dressing the climate change problem, particularly given the United States' curre nt reliance on coal for almost half of its electricity production." [FN8]

2

### The use of carbon dioxide for enhanced o il recovery (EOR) is also generally recognized as an important intermediate step in developing EOR, because the knowledge and technology is already there to begin to use it. "T he injection of CO2 in deep geological formations involve s many of the same technologies that have been developed in the oil and ga s exploration and pr oduction industry. Well-drilling technology, inje ction technology, computer simulation of storage reservoir dynamics and monitoring methods from existing applications are being developed further for design and opera tion of geological storage." [FN9]

Individual Response: EPA agrees that GS is one technology in a portfolio of options, including energy conservation, efficiency improvements, a nd the use of alternative fuels and renewable energy sources, that could be deployed to re duce CO2 emissions. However, the use of and investment in these technologies is outs ide the scope of the UIC GS rulemaking.

EPA clarifies that the intent of the Class VI regu lation is not to promote or encourage the use of GS, but, instead to ensure protection of USDWs where GS technologies are deployed. Please see the remainder of EPA’s responses to this commen t for further details. For additional information on EPA’s final regulatory appr oach, please see the final rule and preamble as well as the rulemaking docket.

Letter ID: 0260 Comment ID: 22386 Letter Lines: 177 to 185

Comment Code: 1680 1.3.8 Don't overstate ris k, don't stigmatize CO2

Comment: III. General Comments

EPA must be careful to avoi d labeling sequestered CO2 as a waste, pollutant or contaminant. Regulations should requ ire storage operators to properly characterize the CO2 they intend to stor e and protocols for storage should be based on that characterization. Broad sweep ing characterizations of sequestered CO2 as hazardous waste, however, should be avoided due to the potential

deterrent such characterizations will ha ve on entities attempting to develop carbon capture and sequestr ation (CCS) projects.

Individual Response: EPA adds that the requirements of the GS rule are tailored to the nature of the CO2 itself and risks associated with the inj ection of CO2, and do not address the status of CO2 as either a pollutant, commodity, or waste.

Finally, EPA notes that the intent of the GS rule is not to promot e CCS; rather, the purpose of the rule is to ensure that, where deployed, GS pe rformed in a manner that protects USDWs from endangerment.

Letter ID: 0260 Comment ID: 22387 Letter Lines: 187 to 190

3

### Comment Code: 1000 1. General and Administrative Comments

Comment: IV. Comments on Identified Issues

The following comments are directed to the specific questions raised in the proposed rule.

Individual Response: EPA acknowledges the comment. Pleas e see the remainder of EPA's responses to this letter for further details. Fo r additional information on EPA's final regulatory approach, please see the final rule and pr eamble as well as the rulemaking docket.

Letter ID: 0260 Comment ID: 22388 Letter Lines: 192 to 203

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

Comment: "3. Tracking the Results of CO 2 GS Research Projects"

The EPA states,"4-D seismic monitoring ma y be a valuable to ol for CO2 plume tracking." The emphasis on "may be" reflects the fact that th ere are a variety of monitoring tools available and also a variety of site -specific geologic

conditions thus the tools used to track th e location of the CO2 plume should be flexible, and the regulations should re flect this flexibility in choosing methods. "4-D seismic monitoring" has been demonstrated as a re search tool but may not be needed as a minimum operating tool. "4-D seismic monitoring" is an extremely expensive option. However, geoche mical sampling methods and monitoring

wells can be used to determine the dist ribution of CO2 within a reservoir and monitor for leakage.

Individual Response: EPA agrees that seismic monitoring is not applicable or appropriate for all sites. The final rule (at §146.90(g)) requires ow ners or operators to perform monitoring to track the extent of the CO2 plume and pressure front. The owner or operator must use direct methods to monitor for pressure changes in the injection zone. Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys an d/or down-hole CO2 det ection tools) are also required unless the Director determines, based on site-specific geology, that such methods are not appropriate.

EPA is affording Director's disc retion regarding the use of geophys ical techniques at some sites because the Agency recognizes that geophysical methods are not appropriate in all geologic settings. For example, geophysical methods are diffi cult to execute in areas that are structurally and topographically complex or where lithologies have limited contrast in density, porosity, permeability, and other physical properties. EPA clarifies that this determination will be made by the Director based on the site-specific geologi c information submitted by the owner or operator with the permit application.

EPA acknowledges the commenters' concern about th e cost of geophysical techniques. However,

4

### EPA believes that tracking of the plume is essential for protection of USDWs from endangerment at GS sites and that geophysical methods are necessary for such tracking.

EPA also agrees that other data may be usef ul for tracking the CO2 plume. For example, geochemical data collected above the confini ng layer, as required under §146.90(d), will allow the owner or operator and permitting authority to identify any changes in subsurface geochemistry that may indicate fluid movement when compared to baseline geochemistry data collected during site characterization.

EPA is developing guidance on testing and mon itoring to assist owne rs or operators and Directors in evaluating requi rements under §146.90, including pr oposed monitoring plans. The guidance describes available technologies a nd recommended approaches for implementing a testing and monitoring plan, including pre-ope rational geophysical l ogging and testing of injection wells, MITs, injecti on well testing during operation, groundwater quality monitoring, tracking the CO2 plume and pressure front, a nd soil gas and surface air monitoring which may be required by the UIC Director for specific GS projects. Th e guidance can be found on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_se questration.cfm.

Letter ID: 0260 Comment ID: 22389 Letter Lines: 205 to 213

Comment Code: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment)

Comment: "G. How Would This Proposal Affect Ex isting Injection Wells Under the UIC Program?"

EPA's approach to CO2 injection in Cla ss II and Class V wells for EOR/EGR as long as oil/gas production continues does nottake 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 issu ed a GS permit and the construction requirements needs to be grandfathered into the Class VI well classification.

Individual Response: EPA agrees that many Class I, Cl ass 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 en gineered 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 pr ojects must be subject to the operational, MIT, monitoring, reporting, plugging, and post-inject ion site care and site closure requirements

in the final GS rule. See the discussion of EPA's fi nal regulatory approach in the preamble to the GS rule for additional detail on these requirements.

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### Letter ID: 0260 Comment ID: 22393 Letter Lines: 215 to 230

Comment Code: 2100 1.6 Target Geologic Formations for GS

Comment: "H. What Are the Target Geologica l Formations for GS of CO2?"

Basin Electric urges the EPA to not arbi trarily exclude certain formations for the injection of CO2. Rather, determ ination of appropriate geology for sequestration should be site specific.

Broad exclusions of geological formations would result in the non-utilization of large area of potential storage. In ad dition, exclusion of un-mineable coal seams would prevent the recove ry of potentially large quan tities of natural gas.

State Directors should have the responsib ility of determining whether or not injection into coal seams, oil and gas formations, locations above the lowermost underground source of drinking water (USDW), etc. should be permissible. Rather than a broad exclusion, proper site se lection, site characterization and engineering should be utilized in determ ining the suitability of a potential sequestration site.

Individual Response: EPA clarifies that the GS rule does not categorically prec lude 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, required at §146.83 of the GS rule. The Cla ss VI siting, well cons truction and operation, monitoring and testing, and post-inj ection site care and site closur e 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 can be accomplished in a manner that protects USDWs and meets all of the requi rements of the GS rule, the project may be permitted as a Class VI well.

Under the Final Rule, EPA believes that state pe rmitting authorities are in the best position to make determinations about the appropriateness of a particular site based on all available information, including drinking water supply needs.

EPA acknowledges that there may be risks associat ed with GS, particularly regarding GS into formations such as coal seams, basalts, salt dom es, or shales, which have been the subject of limited experimental projects in the past. For this reason, the Agency is using an adaptive approach to regulate GS injecti on. EPA will collect and review proj ect data on early GS projects, including those that inject into various formation types, to determine whether the appropriate amount and types of information and documentati on are being collected. EPA plans, every six years, to collect and review data on GS projects to determin e 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.

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### 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.

Letter ID: 0260 Comment ID: 22394 Letter Lines: 232 to 266

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

Comment: "I. Is Injected CO2 Considered a Hazardous Waste Under RCRA?

Under the proposal, EPA states that it ca nnot make a categorical determination as to whether injected CO2 is hazar dous under RCRA. It suggests the burden should be on the operators to characteri ze their CO2 stream as part of the permit application to determine if the injectate is considered hazardous as defined in 40 CFR Part 261. RCRA regul ates the production, management, and disposal of wastes and RCRA's potential a pplication in the case of CO2 injectate is dependent upon the existence of a solid waste. If the material is a solid waste, the law requires further analysis to determine if it is also a hazardous

waste.

Injected CO2 should be considered a pr oduct or a commodity and not a solid waste. Leaving the question to be resolved when operators characterize their CO2 streams with the potential that RCRA liability may attach will be a deterrent to CO2 storage projects. Basin Electric urges the EPA to make a determination under its RCRA authority the CCS activities mee ting Class VI permit requirement do not equate discarding the CO2. By so doing, Cl ass VI CO2 injection operations would not be considered waste management activit ies and would not be subject to RCRA.

EPA should view CCS as a resource, not a waste. EPA should specifically exempt injected CO2 streams from coverage by RCRA and develop requireme nts tailored to this material if necessary to ensure further environmenta l protection beyond that provided by the UIC permitting process.

As further justification for this position, simply consider the success of existing acid gas injection operations into depleted oil and gas reservoirs conducted under the existing pr otective UIC regulations. Im purities, such as H2S or mercaptans, should not trigger a cla ssification under RCRA. The proposed rule has adequate protection for drinking water aquifers a nd addresses corrective action, financial assurance requiremen ts, and long-term monitoring after closure. These requirements negate th e need for any RCRA regulation. Basin Electric wants to avoid open-ended and e nhanced liabilities and risks resulting from requirements that do not signif icantly contribute to health and environmental protection.

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### Individual Response: EPA clarifies that the GS rule does not address the status of CO2 as a pollutant or a commodity. Under the SDWA and the UIC program, EPA regulates the injection of a range of fluids, which may include polluta nts and commodities, rega rdless of how they are characterized, for the purpose of protecting US DWs. Comments related to existing acid gas injection operations are outside the scope of the GS rulemaking.

EPA also notes that the final GS rule, which a dds new regulations for Class VI wells under the Safe Drinking Water Act (SDWA), is not ma king any changes to the RCRA regulations. However, with respect to RCRA, EPA received many comments regarding the applicability of the RCRA regulations and statute to CO2 stream s that are geologically sequestered under the final Class VI UIC well requirements. As a resu lt, 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 po ssible 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 Agen cy will consider issues particular to RCRA in the context of that separate rulemaking, and recommends that the commenter read that proposed rule when it is published. The Agency notes that commenters who wish to submit comments on the RCRA proposal will need to do so duri ng the comment period for that rule.

Letter ID: 0260 Comment ID: 22395 Letter Lines: 268 to 294

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment)

Comment: "J. Is Injected CO2 Considered a Ha zardous Substance Under CERCLA?"

EPA seeks comment on whether Class VI permittees could be exempt from CERCLA under its "federally permitted release" provision. First, liabi lity under CERCLA depends on whether there has been a dispos al of hazardous substances. While CO2 is not a CERCLA hazardous substance, EP A suggests in the preamble that the makeup of a particular injected CO2 st ream may trigger a CERCLA analysis. However, the preamble also states that CERCLA's "federally permitted releases" provision exempts releases in complian ce with a UIC Permit under the Safe Drinking Water Act (SDWA) from CERCLA liab ility. This exemption in and of itself should put the issue to rest . EPA should make clear that this exclusion provides a shield from Superfund lia bility. We urge the EPA to address the longterm liability for stored CO2 w ithin the UIC Class VI Well Permit. EPA should avoid creating unnecessary hurdles for the succe ssful deployment of CCS by assuming that potential applications of other statutes that may come into play.

Basin Electric requests th at EPA recognizes that CO2 injection and storage is exempt from CERCLA liabiliti es and regulates this activity by compliance with the UIC Class VI Well Permit. Also, please see previous comments on the exclusion of the injected CO2 stream as a hazardous waste (RCRA). If the UIC Program cannot coordinate these exclusi ons for RCRA and CERCLA, BEPC requests that a legislative op tion be considered.

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### EPA should establish a single, clear, a nd reasonable regulatory structure for managing risks and liabilities for CCS pr ojects. The process to obtain a UIC Class VI Permit and defining the Area of Review (AoR) will provide proper protections of the USDWS, environment, and health.

Individual Response: CO2 itself is not listed as a hazardous substance under CERCLA however, the CO2 stream may contain a listed hazardous substance (such as mercury) or may

mobilize substances in the subsurface that could react with ground water to produce listed hazardous substances (such as sulf uric acid). Whether such subs tances may result in CERCLA liability from a sequestration f acility depends entirely on the composition of the specific CO2

stream and the environmental media in which it is stored (e.g., soil or ground water). CERCLA exempts from liability, under CERCLA section 107, 42 U.S.C. 9607, certain "federally permitted releases" as defined in CERCLA, 42 U.S.C. 9601(10). Class VI perm its will need to be carefully structured to ensure that they prevent potential releases from the well which are outside the scope of the Class VI permit.

Furthermore, EPA is promulgating the GS rule un der the authority of th e SDWA. To the extent the commenter is seeking interpretations of CE RCLA and its related pr ovisions, such as the definition of a federally permitted release, such interpretations are beyond the scope of this rulemaking.

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

Regarding long term liability, once an owner or operator has met all regu latory requirements

under Part 146 for Class VI wells and the Dire ctor has approved site closure pursuant to requirements at §146.93, the owner or operato r will generally no longer be subject to enforcement for regulatory noncompliance. Furtherm ore, 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 ce rtain circumstances. For example, an owner or operator may be held liable for regulatory noncompliance even afte r site closure was approved if the Director relied on erroneous information (e.g., erroneous modeling data) provid ed by the owner or operator when approving site closure.

Separate from EPA's authority to enforce regul atory compliance, an owner or operator may be subject to a §1431 response orde r even after proper site cl osure is approved under §146.93. Under §1431 the Administrator may require an ow ner 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 pres ent an imminent and s ubstantial endangerment to the health of persons, and the appropriate Stat e and local authorities ha ve not acted to protect

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### the health of such persons. Th e action may include issuing admi nistrative orders or commencing a civil action for appropriate relief against the ow ner 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 ope rator may remain liable under tort and other remedies, or under other federal statutes includi ng, 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 SD WA 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.

Letter ID: 0260 Comment ID: 22396 Letter Lines: 296 to 312

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones (seeking comment)

Comment: "1. Proposed Geologic Siting Requirements"

EPA requests comments on whether th e final rule should require the

identification and characterization of additional confining and containment zones with the primary (lowermost) confin ing zone that could further impede

vertical fluid movement and allow fo r pressure dissipati on and act as a "secondary containment" requirement.

Basin Electric opposes the inclusion of this secondary containment or characterization requirement as a default provision. In the rare situation where specific site circumstances would warrant , the State Director could exercise discretion and require this additional protection in a Class VI Permit.

This requirement for additional containment zones is not needed if it has already been demonstrated and characterized that the original confinement zone is protective of USDW. The requirement to identify and char acterize additional zones that will impede vertical fluid movement is too broad.

Individual Response: EPA retains the requirement to iden tify additional containment/confining zones, if required by the Di rector, as proposed (§146.83(b)). EPA acknowledges that such additional zones may not be needed in all circumst ances, and clarifies that this requirement is at the Director's discretion, based on his or her understanding of a part icular site. EPA believes that, in some situations, the presence of additional confining and containment zones above the primary (i.e., lowermost) confining zone can improve USDW protecti on. These layers could further impede vertical fluid movement and al low for pressure dissipation, and also provide additional sites for monitoring, mitigation, and re mediation. The Agency's decision is supported by commenters representing states, water associati ons, and an electric utility who assert that these requirements promote a flexible, risk-base d, site-specific approach to characterizing and

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### permitting a site for GS projects, and are intende d to improve understanding of the project as a whole and promote better modeling of the site.

Letter ID: 0260 Comment ID: 22397 Letter Lines: 314 to 327

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

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

Comment: "3. Proposed Injection Well C onstruction Requirements"

EPA seeks comments regarding degradation resistant well constr uction materials,

such as acid resistant cements a nd corrosion resistant casing. Dakota

Gasification and Basin Elect ric agree with EPA's pr oposal to not specify materials and provide the owner/operator the flexibility to choose materials within the appropriate cons truction standards. The owne r/operator working with

the State Director should be in the best position to determine a cost effective strategy for construction, corrosion prev ention, and corrosion monitoring that

is best suited for the site conditions. For example, Dakota Gasification's CO2 pipeline and much of the Weyburn fiel d systems are constructed from carbon steel, even though this is not common pract ice in acid gas systems. Due to some of the unique proper ties of this CO2 stream, the corrosion issues have been insignificant after 9 years of continuous service.

Individual Response: EPA recognizes that each GS project will be unique and, for this reason, the rule provides flexibility re garding appropriate materials for Class VI wells. The rule does not specify materials to be used; rather, it provides owne rs or operators with the flexibility to choose, as long as the materials used in Class VI wells are 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, as provided at §146.86(b)(1).

EPA is aware of GS efforts at Weyburn; a pa per summarizing EPA's re view of Weyburn and other large international GS proj ects is in the rulemaking docket. See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the constr uction of Class VI wells. This guidance

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

Letter ID: 0260 Comment ID: 22398 Letter Lines: 329 to 332

Comment Code: 4540 2.5.2 Proposed external MIT requirements

Comment: "5. Proposed Mechanical Integr ity Testing Requirements"

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### The referenced annual tracer survey, temper ature, or noise log is too burdensome and should be changed to a five-yea r frequency or other criteria.

Individual Response: EPA disagrees that a five-year extern al MIT is appropriate. The final GS regulation retains the requirement that owners or operators of Class VI wells must demonstrate injection well external mechanic al integrity at least once a nnually as required under §146.89(c). EPA believes this is justifiable for the prot ection of USDWs from endangerment given the unique nature of CO2 GS relative to other injection operations, including the potential corrosive impact of CO2 in the presence of water and impurities on well materials, the potential geomechanical impacts to well integrity due to CO 2 phase changes, the temperature and pressure effects associated with injecti ng supercritical CO2, and the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA chose a more conservative initial approach in the early stag es of deployment for GS.

A comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that Class I wells injecting corrosive fluids fa il MITs at rates two to three times higher than those that inject non-corrosive fluids (USEPA 1999). Given the pote ntial for CO2 to be corrosive (e.g., in the presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and, for this reason, EPA believes that the tailor ed MIT requirements in the final GS rule are appropriate. For additional info rmation, please see the discussion of MITs in the final rule preamble.

EPA adds that it is using an ad aptive approach to regulating GS. The Agency plans to collect and review data every six years on GS projects, including MIT da ta, to determine whether the appropriate amount and types of information a nd appropriate documentation are being collected,

and to determine if modifications to the requirements are appropriate or necessary.

Letter ID: 0260 Comment ID: 22400 Letter Lines: 334 to 355

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

Comment: "8. Proposed Well Plugging, Post-Inject ion Site Care, and Site Closure Requirements"

EPA is proposing to impose a 50-year post-in jection site care (PIS C) standard as

the default timeframe with the UIC Stat e Director having th e discretion to adjust this time period. Setting the te ntative 50-year fixed timeframe that

could be modified at the State Director 's discretion based on monitoring and modeling data does provide some flexibil ity. However, Basin Electric urges the

EPA to set the timeframe rules in an orde r that minimizes early risk projects and rewards early movers. The recently pa ssed Emergency Economic Stabilization bill that has become law (HR. 1428) provides in Division B sec. 115 tax incentives for carbon dioxide sequestration e ither in secure geological storage or used as a tertiary injectant in a qualified enhanced o il or natural gas recovery project. It is imperative that the monitoring rules do not inhibit the

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### ability of the Secretary of Treasury to give the credit to the appropriate taxpayer who has captured the carbon di oxide. Requiring 50 years of monitoring could preclude early commercial activity. Th e operator should be responsible for the fixed timeframe of 10 years; however , provisions must be enacted for an eventual transfer of liability and long-t erm monitoring to the government, most likely the state. The Interstate Oil an d Gas Commission 10-y ear recommendation was reviewed and rejected. However, sin ce the State Director could modify the timeframe by extending the monitoring time based on monitoring and modeling data, Basin Electric suggests lowering the fixed timeframe to 10 years.

Individual Response: EPA disagrees that a post-injection si te care timeframe of 50 years is excessive for most Class VI wells. EPA proposed a default post-injection s ite care timeframe of 50 years based on a review of research studies , industry reports, and existing environmental programs. This analysis was included in an EPA- prepared background document that is available in the federal docket, titled "Computationa l Modeling of Underground Injection of Carbon

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

For this reason, the GS rule offers owners or op erators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe during the post-injecti on period based on site-specific da ta, pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator to demonstrate, during the permitting process based on substantial data, that an alternative PISC timeframe may be appropriate if it ensu res non-endangerment of USDWs pursuant to requirements at §146.93(c).

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

substantial data exists to demonstrate that an alternative timeframe would be protective of USDWs, or based on data collected during the PISC period, is appropriate to address the range of sites where GS is anticipated to occur, to ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-specific data, and be based on pressure monitoring and USDW impacts.

EPA believes however, that to ensure USDW protection from enda ngerment, a default timeframe for post-injection site care will be necessary in al l but a limited number of cases. This default 50 year post-injection site care ti meframe represents a reasonable and protective monitoring period

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### 14 based on a review of research studies, industr y reports, and existing environmental programs, and evaluation of public comments.

EPA adds that the comment related to the Emer gency Economic Stabilization bill is outside the scope of this rulemaking. EPA adds that the purpos e of the GS rule is no t to incentiv ize the use of GS; rather, the purpose of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.