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:

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

was assigned a Letter ID that corresponds to the last four digits of the docket number of the

original comment (as posted on www.regulations.gov).

• Each response letter includes: comment text; an EPA‐assigned comment code; and an

individual response. These are described and explained below.  

• 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

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appropriately addressed.

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

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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

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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 (C02) 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 (C02)

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 CO2 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 CO2 from the gasification process and provides all the CO2 sequestered in

the largest anthropogenic CO2 sequestration project in the world. Through 2008, Dakota

A Touchstone Energy" Cooperative ~T~

- Equal

Employment

Opportunity

Employer
Stephen 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 CO2 is being used for enhanced oil recovery (EOR) in oil fields near Weyburn,

Saskatchewan. The CO2 is expected to be permanently sequestered in the oil reservoir and

is being monitored by the International Energy Agency (lEA) Weyburn CO2 Monitoring and

Storage Project. The 2000-2004 lEA GHG Weyburn CO2 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 CO2-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

CO2 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 CO2 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 CO2capture

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 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 CO2transport and

injection may already be in place.,,1 Use of CO2for EOR often adds an additional 7-23% of

incremental oil recovery from a field, and depleted oil fields have advantages for CO2

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 CO2 injection

there has been no measurable leakage (Strutt et al., 2003)."3 Thus, EOR is an established

option for CO2sequestration in the Williston Basin, and geological formations are holding

sequestered CO2without leakage. There is an identified need for additional CO2for 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 CO2 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 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 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 CO2 levels in the

atmosphere will not likely be achieved with a single technological option, but CO2 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 CO2 deep underground is large. 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 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 CO2 is "a widespread geological phenomenon," and that '[w]hile there are

differences between natural accumulations and engineered storage, injecting CO2 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 CO2 is, in sum, one of the important tools available for stabilizing

CO2 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 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 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 CO2 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 CO2 as a waste, pollutant or

contaminant. Regulations should require storage operators to properly characterize the CO2

they intend to store and protocols for storage should be based on that characterization.

Broad sweeping characterizations of sequestered CO2 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 CO2 GS Research Projects"

The EPA states,"4-D seismic monitoring may be a valuable tool for CO2 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 CO2 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 CO2 within a reservoir and monitor for

leakage.

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

Program?"

EPA's approach to CO2 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 CO2 that takes place

from this process. CO2, 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 CO2?''

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

CO2• 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 CO2 Considered a Hazardous Waste Under RCRA?

Under the proposal, EPA states that it cannot make a categorical determination as to

whether injected CO2 is hazardous under RCRA. It suggests the burden should be on the

operators to characterize 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 regulates the

production, management, and disposal of wastes and RCRA's potential application 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 product 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

meeting Class VI permit requirement do not equate discarding the CO2• By so doing, Class

VI CO2 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

CO2 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 H2S 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 CO2 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 CO2 is not a CERCLA
Stephen L. Johnson

December 18, 2008

Page 6

hazardous substance, EPA suggests in the preamble that the makeup of a particular

injected CO2 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 CO2 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 CO2 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 CO2 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 CO2 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 CO2

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 1a-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 Electric 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 Williston 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 CO2 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 oil fields have advantages for CO2 

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." [FN2] IPCC's 2005 "Carbon Capture and 

Storage" Report also recognizes 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 sequestered CO2 without leakage. There is 

an identified need for additional CO2 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 CO2 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 60 gigatons (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 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 21st-century.[FN4] The IPCC 

notes that stabilizing CO2 levels in the atmosphere will not likely be achieved 

with a single technological 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 store CO2 deep underground is large. 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 than this, but quantification 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 widespread geological phenomenon," and 

that '[w]hile there are differences between natural accumulations and engineered 

storage, injecting CO2 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 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 responses to this letter for further details. For 

additional information on EPA's final regulatory approach, please see 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 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 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 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." [FN8] 

2
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 

CO2 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." [FN9] 

Individual Response: EPA agrees that GS is one technology in a portfolio of options, including 

energy conservation, efficiency improvements, and the use of alternative fuels and renewable 

energy sources, that could be deployed to reduce CO2 emissions. However, the use of and 

investment in these technologies is outside the scope of the UIC GS rulemaking. 

EPA clarifies that the intent of the Class VI regulation 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 comment for further details. For additional information 

on EPA’s final regulatory approach, 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 risk, don't stigmatize CO2 

Comment: III. General Comments 

EPA must be careful to avoid labeling sequestered CO2 as a waste, pollutant or 

contaminant. Regulations should require storage operators to properly 

characterize the CO2 they intend to store and protocols for storage should be 

based on that characterization. Broad sweeping characterizations of sequestered 

CO2 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. 

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 injection 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 promote CCS; rather, the purpose of the 

rule is to ensure that, where deployed, GS performed 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. Please see the remainder of EPA's 

responses to this letter for further details. For additional information on EPA's final regulatory 

approach, please see the final rule and preamble 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 CO2 GS Research Projects" 

The EPA states,"4-D seismic monitoring may be a valuable tool for CO2 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 CO2 plume should be 

flexible, and the regulations should reflect this flexibility in choosing 

methods. "4-D seismic monitoring" has been demonstrated as a research tool but 

may not be needed as a minimum operating tool. "4-D seismic monitoring" is an 

extremely expensive option. However, geochemical sampling methods and monitoring 

wells can be used to determine the distribution 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 owners 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 and/or down-hole CO2 detection tools) are also 

required unless the Director determines, based on site-specific geology, that such methods are 

not appropriate. 

EPA is affording Director's discretion regarding the use of geophysical techniques at some sites 

because the Agency recognizes that geophysical methods are not appropriate in all geologic 

settings. For example, geophysical methods are difficult 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 geologic information submitted by the owner or operator 

with the permit application. 

EPA acknowledges the commenters' concern about the 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 useful for tracking the CO2 plume. For example, 

geochemical data collected above the confining 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 monitoring to assist owners or operators and 

Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s 

website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.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 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. 

Individual 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. 

5
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 Geological Formations for GS of CO2?" 

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

the injection of CO2. Rather, determination 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 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. 

Individual Response: 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, 

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 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. 

Under the Final Rule, EPA believes that state permitting 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 associated with GS, particularly regarding GS into 

formations such as coal seams, basalts, salt domes, 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 injection. EPA will collect and review project data on early GS projects, 

including those that inject into various formation types, to determine whether the appropriate 

amount and types of information and documentation are being collected. EPA plans, every six 

years, to collect and review data on GS projects to determine whether the appropriate amount 

and types of information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

6
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 issues (seeking comment) 

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

Under the proposal, EPA states that it cannot make a categorical determination 

as to whether injected CO2 is hazardous under RCRA. It suggests the burden 

should be on the operators to characterize 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 regulates the production, management, and 

disposal of wastes and RCRA's potential application 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 product 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 meeting Class VI permit requirement do not 

equate discarding the CO2. By so doing, Class VI CO2 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 CO2 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 H2S 

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. 

7
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 pollutants and commodities, regardless of how they are 

characterized, for the purpose of protecting USDWs. 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 adds new regulations for Class VI wells under the 

Safe Drinking Water Act (SDWA), is not making 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 streams that are geologically sequestered under the 

final Class VI UIC well requirements. As a result, EPA has decided to initiate a separate 

proposed rulemaking specifically to examine the issue of RCRA applicability to CO2 streams 

being geologically sequestered, including the possible option of a conditional exemption from 

the RCRA requirements for CO2 GS in Class VI wells. EPA will consider these comments as 

part of its development of that proposal. The Agency will consider issues particular to RCRA in 

the context of that separate rulemaking, and recommends that the commenter read that proposed 

rule when it is published. The Agency notes that commenters who wish to submit comments on 

the RCRA proposal will need to do so during the comment period for that rule. 

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 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 CO2 

is not a CERCLA hazardous substance, EPA suggests in the preamble that the 

makeup of a particular injected CO2 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 CO2 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 CO2 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 CO2 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. 

8
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. 

Individual Response: CO2 itself is not listed as a hazardous substance under CERCLA 

however, the CO2 stream may contain a listed hazardous substance (such as mercury) or may 

mobilize substances in the subsurface that could react with ground water to produce listed 

hazardous substances (such as sulfuric acid). Whether such substances may result in CERCLA 

liability from a sequestration facility depends entirely on the composition of the specific CO2 

stream and the environmental media in which it is stored (e.g., soil or ground water). CERCLA 

exempts from liability, under CERCLA section 107, 42 U.S.C. 9607, certain "federally permitted 

releases" as defined in CERCLA, 42 U.S.C. 9601(10). Class VI permits will need to be carefully 

structured to ensure that they prevent potential releases from the well which are outside the scope 

of the Class VI permit. 

Furthermore, EPA is promulgating the GS rule under the authority of the SDWA. To the extent 

the commenter is seeking interpretations of CERCLA and its related provisions, such as the 

definition of a federally permitted release, such interpretations are beyond the scope of this 

rulemaking. 

The UIC program Director has authority under SDWA §1423 to address potential compliance 

issues (e.g., potential releases that may endanger USDWs) resulting from injection violations in 

the unlikely event that a remedial response is necessary. Although EPA anticipates that the need 

for emergency or remedial actions at GS sites will be rare, the GS rule requires, at §146.94, that 

emergency and remedial response plans be developed and updated to address such events and 

that owners or operators demonstrate that financial resources are set aside to implement the plans 

if necessary, per §146.85. 

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

under Part 146 for Class VI wells and the Director has approved site closure pursuant to 

requirements at §146.93, the owner or operator will generally no longer be subject to 

enforcement for regulatory noncompliance. Furthermore, their financial instrument as required 

under §146.85 will be released if it was not used. However, even if a site closure is approved 

under §146.93, an owner or operator may be held liable for regulatory noncompliance (including 

violation of 40 CFR 144.12) in certain circumstances. For example, an owner or operator may be 

held liable for regulatory noncompliance even after site closure was approved if the Director 

relied on erroneous information (e.g., erroneous modeling data) provided by the owner or 

operator when approving site closure. 

Separate from EPA's authority to enforce regulatory compliance, an owner or operator may be 

subject to a §1431 response order even after proper site closure is approved under §146.93. 

Under §1431 the Administrator may require an owner or operator to take necessary response 

measures if he or she receives information that a contaminant is present or is likely to enter a 

public water system or an USDW, which may present an imminent and substantial endangerment 

to the health of persons, and the appropriate State and local authorities have not acted to protect 

9
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. 

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 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. 

Individual Response: EPA retains the requirement to identify additional containment/confining 

zones, if required by the Director, as proposed (§146.83(b)). EPA acknowledges that such 

additional zones may not be needed in all circumstances, and clarifies that this requirement is at 

the Director's discretion, based on his or her understanding of a particular 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 protection. These layers could 

further impede vertical fluid movement and allow for pressure dissipation, and also provide 

additional sites for monitoring, mitigation, and remediation. The Agency's decision is supported 

by commenters representing states, water associations, and an electric utility who assert that 

these requirements promote a flexible, risk-based, site-specific approach to characterizing and 

10
permitting a site for GS projects, and are intended 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 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 CO2 

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 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 regarding appropriate materials for Class VI wells. The rule does not 

specify materials to be used; rather, it provides owners 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 paper summarizing EPA's review of Weyburn and 

other large international GS projects 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 construction of Class VI wells. This guidance 

will be available on EPA’s website at 

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

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

Comment Code: 4540 2.5.2 Proposed external MIT requirements 

Comment: "5. Proposed Mechanical Integrity Testing Requirements" 

11
The referenced annual tracer survey, temperature, or noise log is too burdensome 

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

Individual Response: EPA disagrees that a five-year external MIT is appropriate. The final GS 

regulation retains the requirement that owners or operators of Class VI wells must demonstrate 

injection well external mechanical integrity at least once annually as required under §146.89(c). 

EPA believes this is justifiable for the protection 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 CO2 phase changes, the temperature and pressure 

effects associated with injecting 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 stages 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 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 (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 tailored MIT requirements in the final GS rule are 

appropriate. For additional information, please see the discussion of MITs in the final rule 

preamble. 

EPA adds that it is using an adaptive approach to regulating GS. The Agency plans to collect and 

review data every six years on GS projects, including MIT data, to determine whether the 

appropriate amount and types of information and appropriate documentation are being collected, 

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

Letter ID: 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-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 

12
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 10-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. 

Individual Response: EPA disagrees that a post-injection site care timeframe of 50 years is 

excessive for most Class VI wells. EPA proposed a default post-injection site 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 "Computational Modeling of Underground Injection of Carbon 

Dioxide for Determination of Area-of-Review and Potential Risk to Underground Sources of 

Drinking Water." EPA assessed various default timeframes based on additional review of 

research studies and evaluation of public comments. While numerous commenters suggested that 

EPA shorten the monitoring timeframe, none of the commenters provided sufficient data or other 

evidence to warrant a change in the proposed timeframe. While the 10- or 30-year timeframe 

suggested by some of these commenters may be within the timeframe suggested in some studies, 

EPA believes that the potential risks of endangering USDWs will likely not decline within these 

timeframes and available data, including data submitted by commenters, do not support a 

different default timeframe. However, EPA recognizes that alternative timeframes may be 

appropriate under limited, specific circumstances. 

For this reason, the GS rule offers owners or operators flexibility regarding the duration of the 

PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC 

timeframe during the post-injection period based on site-specific data, pursuant to requirements 

at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator 

to demonstrate, during the permitting process based on substantial data, that an alternative PISC 

timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to 

requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in all but a limited number of cases. This default 50 

year post-injection site care timeframe represents a reasonable and protective monitoring period 

13
14

based on a review of research studies, industry reports, and existing environmental programs, 

and evaluation of public comments. 

EPA adds that the comment related to the Emergency Economic Stabilization bill is outside the 

scope of this rulemaking. EPA adds that the purpose of the GS rule is not to incentivize the use 

of GS; rather, the purpose of the GS rule is to ensure that, where GS is deployed, it is conducted 

in a manner that protects USDWs from endangerment.