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.
BEFORE THE UNITED STATES 

ENVIRONMENTAL PROTECTION AGENCY 

____________________________________________ 

) 

Notice of Proposed Rulemaking ) 

Federal Requirements Under the ) 

Underground Injection Control (UIC) Program ) EPA-HQ-OW-2008-0390 

for Carbon Dioxide (CO2) ) FRL-8695-3 

Geologic Sequestration (GS) Wells ) 

 ) 

 ) 

73 Fed. Reg. 43492 (July 25, 2008) ) 

____________________________________________)

Individual Additional Comments 

of the 

Natural Resources Defense Council 

A. Introduction 

The Natural Resources Defense Council (NRDC) thanks EPA for the opportunity to 

comment on the Proposed Rule on carbon dioxide sequestration wells under the 

Underground Injection Control (UIC) Program. 

NRDC is a national, nonprofit organization of scientists, lawyers and environmental 

specialists dedicated to protecting public health and the environment. Founded in 1970, 

NRDC has more than 1.2 million members and online activists nationwide, served from 

offices in New York, Washington D.C., San Francisco, Los Angeles, Chicago and 

Beijing. 

NRDC has submitted the bulk of its comments on the proposed rule jointly with the 

Clean Air Task Force, Clean Water Action, Environmental Defense Fund and Western 

Resource Advocates. We submit these additional comments to cover three areas on which 

we would like to draw particular attention and elaborate on our views. These areas are: 

• the definition of GS and authority, and sequestration in hydrocarbon reservoirs; 

• pressure management; and 

• closure. 
Having participated in the discussions of the multi-stakeholder group that will be 

submitting comments on the same topics, we felt that good progress was made towards 

forming a consensus on these topics. Nonetheless, we felt unable to sign on to those joint 

recommendations and proposed language, for reasons that will become clear below. We 

appreciated the extension of the public comment period that was granted by Assistant 

Administrator Benjamin Grumbles, announced in the Federal Register on November 21 

and confirmed in Director Cynthia C. Dougherty’s letter of November 24. 

B. Definition of GS 

Geologic sequestration and authority

In the proposed rule, EPA has defined geologic sequestration as follows [FR p. 43535, 

§146.81(d)]: 

“Geologic sequestration means the long-term containment of a gaseous, 

liquid or supercritical carbon dioxide stream in subsurface geologic 

formations. This term does not apply to its capture or transport.” 

The proposed rule has cited authority for EPA to regulate GS under the Safe Drinking 

Water Act. However, we believe that EPA should exercise its authority under the Clean 

Air Act as well to regulate GS for the added purpose of preventing releases to the 

atmosphere, and not just for the purpose of protecting USDWs. Under such authority, the 

Agency should ensure that any wells permitted for the purposes of GS meet an adequate 

permanence standard, such as that already promulgated in the UIC rules by the state of 

Washington, which was based on the IPCC’s findings in its Special Report on Carbon 

Capture and Storage1

: 

“Permanent sequestration means the retention of greenhouse gases in a 

containment system using a method that is in accordance with standards 

approved by the department and that creates a high degree of confidence 

that substantially ninety nine percent of the greenhouse gases will remain 

contained for at least one thousand years.”2

Under this added authority, EPA should ensure that Class VI is adequate for the purposes 

of protecting USDWs and for preventing releases of CO2 to the atmosphere. 

 

1

 In its technical summary, IPCC’s Special Report on Carbon Capture and Storage states that “With regard 

to global risks, based on observations and analysis of current CO2 storage sites, natural systems, 

engineering systems and models, the fraction retained in appropriately selected and managed reservoirs is 

very likely to exceed 99% over 100 years, and is likely to exceed 99% over 1000 years. Similar fractions 

retained are likely for even longer periods of time, as the risk of leakage is expected to decrease over time 

as other mechanisms provide additional trapping.” 

2

 WAC 173-407-110 Definitions to Part II. 
Other wells permitted for GS, whether for that sole purpose or for GS and other purposes, 

should also be subject to regulatory requirements sufficient both to protect USDWs and 

to prevent releases of CO2 to the atmosphere. Such requirements include, but are not 

limited to, adequate site characterization, monitoring, modeling, corrective and remedial 

action and closure standards, as well as other requirements that EPA has proposed for 

Class VI. We cannot endorse the classification of either Class II (as was proposed or as 

modified by some other commenters) wells or Class VI wells as proposed by EPA in the 

rule, as the definition only covers protection of USDWs. 

Sequestration in hydrocarbon reservoirs

We also wish to comment on the distinction between a Class II EOR project and 

sequestration in oilfields. Currently, EOR operators purchase CO2 for injection at an 

expense. Consequently, CO2 is a valuable commodity to EOR operators and is treated 

accordingly. CO2 purchases from natural, and, to a lesser extent, anthropogenic sources, 

represent a major cost to a CO2-EOR operation, often as high as 50% of overall project 

costs. As such, operators have had a strong incentive to minimize the amount of CO2

purchased and injected, and frequently have relied on the injection of water alongside the 

CO2 in a process known as Water-Alternating-Gas (WAG). To minimize the amount of 

CO2 purchased, CO2 is not intentionally emitted or vented to the atmosphere during 

operations or after operations cease. Any injected CO2 that returns to the surface during 

production operations is separated from the hydrocarbons and re-injected for additional 

enhanced recovery use. Approximately 30% to 50% of the injected CO2 volume typically 

remains in the oil or gas reservoir after production operations cease. 

However, this current economic rationale for recycling CO2 does not assure long-term 

retention of the injected CO2 for several reasons and thus does not provide a basis for 

assuming that either “business as usual” EOR activities or EOR activities modified to 

increase amounts of CO2 injected should qualify as GS, without additional showings and 

regulatory requirements. Accordingly, no wells permitted only under Class II rules as 

they now stand should be treated as GS activities. 

Long-term retention of injected CO2 in Class II wells is not assured, first, because current 

recycling activities are based on economic incentives that can change as the market price 

for purchasing CO2 changes. Second, the economic incentive to prevent leaks ends when 

CO2 purchases for additional production ceases. Third, the fields where EOR is being 

practiced were not selected specifically for their suitability for long-term CO2 retention 

and were not subject to any regulatory screening to assess such suitability. Fourth, in a 

carbon constrained-world, where there is an economic incentive to maximize the amount 

of CO2 injected in oilfields, additional injection could lead to a change in the risk profile 

to USDWs that exceeds common practice of Class II operations to date. Current Class II 

operations have no real reason or incentive to exceed the original reservoir pressure in the 

oilfield: the resulting pressure drop after primary recovery is only partly compensated for 

or equaled during secondary and tertiary recovery. Exceeding original reservoir pressure 

could lead to conditions that are closer to or exceed the tensile or shear fracture limits of 
the reservoir or fault slippage pressures. The additional pressure could also affect a given 

caprock’s ability to prevent CO2 or other reservoir fluid leakage through it, as pressure 

approaches or exceeds the capillary entry pressure for the caprock. Finally, the larger 

volumes of CO2 injected could lead to CO2 or reservoir fluids approaching of breaching 

spill points in the reservoir, and/or a greater volume of displaced fluids and a larger area 

of elevated pressure. 

Similar considerations prevent wells regulated under other existing UIC classifications 

from being treated as GS activities. 

 

For all of these reasons, we oppose any approach that allows wells that are not subject to 

the necessary requirements to be defined and treated as GS activities. All CO2 injection 

activities that are treated under EPA rules as GS projects to protect USDWs and to 

prevent releases to the atmosphere, whether conducted solely for GS purposes or for 

additional purposes, must be reviewed and permitted pursuant to adequate rules set forth 

for those injection activities. EPA should promulgate such rules under the current 

rulemaking for Class VI, taking into account differences in target reservoir types as 

needed. 

C. Pressure management 

[FR p. 43538, §146.88(a)] EPA has proposed to adopt an injection pressure limit equal to 

90 percent of the fracture pressure in the injection zone. This is a high number, and there 

will be cases where it is prudent to lower limits. Since injection is likely to take place in 

diverse geologic settings, we believe that those limits should be calculated individually, 

taking into account a number of geologic factors each time, which we attempt to 

incorporate in the proposed language below. Nonetheless, we believe that EPA should 

maintain a maximum upper limit (equal to or less than 90 percent of the fracture pressure 

in the injection zone), so as to avoid cases where studies might appear to support higher 

limits that would not be advisable. We also consider the “Except during stimulation” 

qualifier as confusing and creating a loophole and we urge that it be removed. Finally, the 

pressure limits themselves should refer to the confining zone and not the injection zone. 

We offer the following language as a starting point: 

“The owner or operator must ensure that injection pressure does not 

exceed [90] percent of the fracture pressure of the confining zone. The 

owner or operator must comply with a maximum injection pressure limit 

approved by the Director and specified in the permit. In approving a 

maximum injection pressure limit, the Director must consider the results 

of well tests and, where appropriate geomechanical or other studies, that 

assess the risks of tensile failure and shear failure. Limits shall be 

calculated so as to assure that pressure will avoid initiation or propagation 

of fractures in the confining zone or cause otherwise non-transmissive 

faults transecting the confining zone to become transmissive. In no case 
may injection pressure cause movement of injection or formation fluids 

that endangers a USDW.” 

The maximum upper limit should not be used as a default in place of tests and studies 

that should be used to establish appropriate limits for specific sites – we urge EPA to 

ensure that this is built into the rule language. The consideration of both tensile and shear 

failure is necessary in carrying out a rigorous evaluation, in our view, as is the 

requirement not to cause otherwise non-transmissive faults transecting the confining zone 

to become transmissive. We also urge EPA to compile a list of quality criteria against 

which the results of the mentioned tests and studies will be evaluated – these need to be 

transparent and capable of screening adequate tests from inadequate ones. Pressure limits 

should also ensure that no significant risks from seismicity are posed, and EPA should 

incorporate appropriate language in the setting of pressure limits. 

We further believe that the established phrasing “so as to assure that”, used in Class II, is 

preferable to other formulations such as “with a reasonable degree of certainty”. We also 

believe that the proposed rule’s language on movement of fluids “that endangers a 

USDW” is more protective and preferable to the wording “into a USDW”, and preferable 

to references to §144.12(a). As mentioned above, the rule should be drafted to assure no 

releases to the atmosphere as well. 

D. Closure 

[FR p. 43540, §146.93(b)] EPA has proposed an arrangement whereby the operator 

continues to monitor the site for a minimum of 50 years after the cessation of injection, 

unless the operator can demonstrate to the satisfaction of the Director that the project no 

longer poses an endangerment to USDWs and that the CO2 plume and pressure front have 

stabilized. 

While 50 years is not a number that will apply in all cases and projects, we do believe 

that it is appropriate as a default at today’s level of our understanding and operational 

experience with GS. The option that operators have under the current proposal to obtain 

approval for a lower number, based on actual project performance, should be sufficient to 

deal with situations where 50 years can be demonstrated to be unnecessarily long. Along 

the same lines, there might be situations where 50 years would not suffice, and where the 

Director should require a longer period, as per the current proposal. In assessing nonendangerment to USDWs and plume/pressure front stabilization, we believe that the EPA 

should be far more specific in its requirements. We offer the following language as a 

suggested revision to §146.93(b): 

“(b) The owner or operator shall monitor the site following the cessation 

of injection. 

 (1) The owner or operator shall continue to conduct monitoring as 

specified in the Director-approved post-injection site care and site closure 
plan for at least 50 years following the cessation of injection or until 

closure is authorized. 

 (2) If the owner or operator can demonstrate to the satisfaction of 

the Director before 50 years, based on/pursuant to the criteria in (b), that 

the geologic sequestration project does not and is not expected to pose an 

endangerment to USDWs or result in releases to the atmosphere, the 

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

site closure plan to reduce the frequency of monitoring or may authorize 

site closure before the end of the 50-year period. 

 (3) Prior to authorization for site closure, the owner or operator 

must demonstrate to the Director, based on monitoring, other site-specific 

data, and modeling that is consistent with site performance, that no 

additional monitoring is needed to assure that the geologic sequestration 

project does not and is not expected to pose an endangerment to USDWs 

or any release to the atmosphere. The owner or operator must demonstrate, 

based on the current understanding of the site, including monitoring data 

and modeling, all of the following: (i) the magnitude and extent of the 

project footprint (CO2 plume and the area of elevated pressure); (ii) the 

location of the detectable CO2 plume; (iii) that there is no significant 

leakage of either CO2 or displaced formation fluids that is endangering 

USDWs or creating a potential release to the atmosphere; (iv) that the 

injected or displaced fluids are not expected to migrate in the future in a 

manner that encounters a potential leakage pathway into a USDW or to the 

atmosphere; (v) that the injection wells at the site completed into or 

through the injection zone or confining zone are plugged and abandoned 

in accordance with these requirements; and (vi) any remaining project 

monitoring wells at the site are being managed by a person and in a 

manner acceptable to the Director. 

(4) If such a demonstration cannot be made after the 50-year 

period, the owner or operator must submit to the Director a plan to 

continue post-injection site care.” 

In addition, given the desired permanent nature of CO2 sequestration in the subsurface 

and the importance to the public of ensuring long-term attention to oversight of project 

sites, EPA should adopt provisions to assure long-term stewardship of GS repositories. 

This framework should designate an entity with responsibility for monitoring and 

managing sites after closure has been authorized. The proposed rule authorizes operators 

to stop monitoring, but does not provide for the stewardship of sites following closure. 

This needs to be rectified by EPA. The agency should consider its authority not just under 

the Safe Drinking Water Act, but also under the Clean Air Act to provide the required 

stewardship framework. It is important that the post-closure framework include financing 

provisions that avoid hidden subsidies for private sector operators and are adequate to 

ensure proper site stewardship in the long-term. 
E. Conclusion 

We appreciate the opportunity to provide comments to EPA on this most important 

rulemaking effort. We very much look forward to continuing to work with the Agency on 

this rule, as well as other efforts under the Agency’s existing authority to address the 

significant problem of climate change in the near term. 

Respectfully submitted, 

David Hawkins and George Peridas, Natural Resources Defense Council
Letter ID: 0272 

Commenter: David Hawkins 

Organization: Natural Resources Defense Council 

Letter ID: 0272 Comment ID: 24076 Letter Lines: 64 to 103 ; 300 to 309 

Comment Code: 1210 1.1.1 Comments about the proposed rule 

Comment Code: 1400 1.2 Comments on EPA's Authority to Regulate Injection of CO2 

Comment: B. Definition of GS 

Geologic sequestration and authority 

In the proposed rule, EPA has defined geologic sequestration as follows [FR p. 

43535, §146.81(d)]: 

"Geologic sequestration means the long-term containment of a gaseous, 

liquid or supercritical carbon dioxide stream in subsurface geologic 

formations. This term does not apply to its capture or transport." 

The proposed rule has cited authority for EPA to regulate GS under the Safe 

Drinking Water Act. However, we believe that EPA should exercise its authority 

under the Clean Air Act as well to regulate GS for the added purpose of 

preventing releases to the atmosphere, and not just for the purpose of 

protecting USDWs. Under such authority, the Agency should ensure that any wells 

permitted for the purposes of GS meet an adequate permanence standard, such as 

that already promulgated in the UIC rules by the state of Washington, which was 

based on the IPCC’s findings in its Special Report on Carbon Capture and 

Storage [FN1]: 

"Permanent sequestration means the retention of greenhouse gases in a 

containment system using a method that is in accordance with standards approved 

by the department and that creates a high degree of confidence that 

substantially ninety nine percent of the greenhouse gases will remain contained 

for at least one thousand years." [FN2] 

Under this added authority, EPA should ensure that Class VI is adequate for the 

purposes of protecting USDWs and for preventing releases of CO2 to the 

atmosphere. 

Other wells permitted for GS, whether for that sole purpose or for GS and other 

purposes, should also be subject to regulatory requirements sufficient both to 

protect USDWs and to prevent releases of CO2 to the atmosphere. Such 

requirements include, but are not limited to, adequate site characterization, 

monitoring, modeling, corrective and remedial action and closure standards, as 

1
well as other requirements that EPA has proposed for Class VI. We cannot endorse 

the classification of either Class II (as was proposed or as modified by some 

other commenters) wells or Class VI wells as proposed by EPA in the rule, as the 

definition only covers protection of USDWs. 

[FN1] In its technical summary, IPCC’s Special Report on Carbon Capture and 

Storage states that "With regard to global risks, based on observations and 

analysis of current CO2 storage sites, natural systems, engineering systems and 

models, the fraction retained in appropriately selected and managed reservoirs 

is very likely to exceed 99% over 100 years, and is likely to exceed 99% over 

1000 years. Similar fractions retained are likely for even longer periods of 

time, as the risk of leakage is expected to decrease over time as other 

mechanisms provide additional trapping." 

[FN2] WAC 173-407-110 Definitions to Part II. 

Individual Response: EPA clarifies that the scope of the GS regulation is limited to injection of 

CO2, and that all requirements in the GS rule are designed for the purpose of protecting USDWs 

from endangerment. Consequently, this comment is outside the scope of the rulemaking. The 

SDWA does not provide the UIC Program with the authority to develop regulations for all areas 

related to GS, such as releases to the atmosphere. 

EPA acknowledges that GS falls within the broader context of CCS and the need for regulatory 

clarity to ensure that USDWs are protected from endangerment. In developing the final GS rule, 

the Office of Water coordinated with other Agency program offices and across federal agencies 

(e.g., with the Department of Energy; United States Geological Survey; Bureau of Ocean Energy 

Management, Regulation, and Enforcement, formerly the Minerals Management Service; Bureau 

of Land Management). The Agency continues to evaluate areas of potential applicability of other 

Federal environmental statutes including, but not limited to: the Clean Air Act; the Resource 

Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, 

and Liability Act; and the Marine Protection, Research and Sanctuaries Act to various aspects of 

GS and CCS. The Agency will continue to coordinate on GS and CCS related issues to minimize 

redundancy and maximize efficiencies for owners or operators. For additional information, 

please see the discussion entitled "How Does This Rulemaking Relate to Other Federal 

Authorities and GS and CCS Activities?" in the preamble to the final GS rule. 

Letter ID: 0272 Comment ID: 24077 Letter Lines: 105 to 163 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: Sequestration in hydrocarbon reservoirs 

We also wish to comment on the distinction between a Class II EOR project and 

sequestration in oilfields. Currently, EOR operators purchase CO2 for injection 

at an expense. Consequently, CO2 is a valuable commodity to EOR operators and is 

2
treated accordingly. CO2 purchases from natural, and, to a lesser extent, 

anthropogenic sources, represent a major cost to a CO2-EOR operation, often as 

high as 50% of overall project costs. As such, operators have had a strong 

incentive to minimize the amount of CO2 purchased and injected, and frequently 

have relied on the injection of water alongside the CO2 in a process known as 

Water-Alternating-Gas (WAG). To minimize the amount of CO2 purchased, CO2 is not 

intentionally emitted or vented to the atmosphere during operations or after 

operations cease. Any injected CO2 that returns to the surface during production 

operations is separated from the hydrocarbons and re-injected for additional 

enhanced recovery use. Approximately 30% to 50% of the injected CO2 volume 

typically remains in the oil or gas reservoir after production operations cease. 

However, this current economic rationale for recycling CO2 does not assure longterm retention of the injected CO2 for several reasons and thus does not provide 

a basis for assuming that either "business as usual" EOR activities or EOR 

activities modified to increase amounts of CO2 injected should qualify as GS, 

without additional showings and regulatory requirements. Accordingly, no wells 

permitted only under Class II rules as they now stand should be treated as GS 

activities. 

Long-term retention of injected CO2 in Class II wells is not assured, first, 

because current recycling activities are based on economic incentives that can 

change as the market price for purchasing CO2 changes. Second, the economic 

incentive to prevent leaks ends when CO2 purchases for additional production 

ceases. Third, the fields where EOR is being practiced were not selected 

specifically for their suitability for long-term CO2 retention and were not 

subject to any regulatory screening to assess such suitability. Fourth, in a 

carbon constrained-world, where there is an economic incentive to maximize the 

amount of CO2 injected in oilfields, additional injection could lead to a change 

in the risk profile to USDWs that exceeds common practice of Class II operations 

to date. Current Class II operations have no real reason or incentive to exceed 

the original reservoir pressure in the oilfield: the resulting pressure drop 

after primary recovery is only partly compensated for or equaled during 

secondary and tertiary recovery. Exceeding original reservoir pressure could 

lead to conditions that are closer to or exceed the tensile or shear fracture 

limits of the reservoir or fault slippage pressures. The additional pressure 

could also affect a given caprock’s ability to prevent CO2 or other reservoir 

fluid leakage through it, as pressure approaches or exceeds the capillary entry 

pressure for the caprock. Finally, the larger volumes of CO2 injected could lead 

to CO2 or reservoir fluids approaching of breaching spill points in the 

reservoir, and/or a greater volume of displaced fluids and a larger area of 

elevated pressure. 

Similar considerations prevent wells regulated under other existing UIC 

classifications from being treated as GS activities. 

3
For all of these reasons, we oppose any approach that allows wells that are not 

subject to the necessary requirements to be defined and treated as GS 

activities. All CO2 injection activities that are treated under EPA rules as GS 

projects to protect USDWs and to prevent releases to the atmosphere, whether 

conducted solely for GS purposes or for additional purposes, must be reviewed 

and permitted pursuant to adequate rules set forth for those injection 

activities. EPA should promulgate such rules under the current rulemaking for 

Class VI, taking into account differences in target reservoir types as needed. 

Individual Response: EPA believes that injection for the primary purpose of long term storage 

is sufficiently different from Class II ER operations and warrants tailored requirements in order 

to protect USDWs from endangerment. For example, the volume of CO2 anticipated to be 

injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure 

conditions will also be different, with Class VI injection operations involving large volumes of 

CO2 and likely having higher pressures within their storage formations than Class II ER projects, 

which may lead to fluid movement that endangers a USDW. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. 

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

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

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

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

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

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

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

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

see the discussion on transition of Class II wells in the preamble to the final GS rule. 

The purpose of this rule is not to promote or incentivize the deployment of GS. 

Letter ID: 0272 Comment ID: 24078 Letter Lines: 166 to 213 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4110 2.4.1.1 Injection pressure limitations 

Comment: C. Pressure management 

4
[FR p. 43538, §146.88(a)] EPA has proposed to adopt an injection pressure limit 

equal to 90 percent of the fracture pressure in the injection zone. This is a 

high number, and there will be cases where it is prudent to lower limits. Since 

injection is likely to take place in diverse geologic settings, we believe that 

those limits should be calculated individually, taking into account a number of 

geologic factors each time, which we attempt to incorporate in the proposed 

language below. Nonetheless, we believe that EPA should maintain a maximum upper 

limit (equal to or less than 90 percent of the fracture pressure in the 

injection zone), so as to avoid cases where studies might appear to support 

higher limits that would not be advisable. We also consider the "Except during 

stimulation" qualifier as confusing and creating a loophole and we urge that it 

be removed. Finally, the pressure limits themselves should refer to the 

confining zone and not the injection zone. We offer the following language as a 

starting point: 

"The owner or operator must ensure that injection pressure does not exceed [90] 

percent of the fracture pressure of the confining zone. The owner or operator 

must comply with a maximum injection pressure limit approved by the Director and 

specified in the permit. In approving a maximum injection pressure limit, the 

Director must consider the results of well tests and, where appropriate 

geomechanical or other studies, that assess the risks of tensile failure and 

shear failure. Limits shall be calculated so as to assure that pressure will 

avoid initiation or propagation of fractures in the confining zone or cause 

otherwise non-transmissive faults transecting the confining zone to become 

transmissible. In no case may injection pressure cause movement of injection or 

formation fluids that endangers a USDW." 

The maximum upper limit should not be used as a default in place of tests and 

studies that should be used to establish appropriate limits for specific sites - 

we urge EPA to ensure that this is built into the rule language. The 

consideration of both tensile and shear failure is necessary in carrying out a 

rigorous evaluation, in our view, as is the requirement not to cause otherwise 

non-transmissive faults transecting the confining zone to become transmissible. 

We also urge EPA to compile a list of quality criteria against which the results 

of the mentioned tests and studies will be evaluated - these need to be 

transparent and capable of screening adequate tests from inadequate ones. 

Pressure limits should also ensure that no significant risks from seismicity are 

posed, and EPA should incorporate appropriate language in the setting of 

pressure limits. 

We further believe that the established phrasing "so as to assure that", used in 

Class II, is preferable to other formulations such as "with a reasonable degree 

of certainty". We also believe that the proposed rule’s language on movement of 

fluids "that endangers a USDW" is more protective and preferable to the wording 

"into a USDW", and preferable to references to §144.12(a). As mentioned above, 

the rule should be drafted to assure no releases to the atmosphere as well. 

5
Individual Response: EPA disagrees with the suggestion that injection pressure be set at less 

than 90 percent of fracture pressure. EPA believes that a lower pressure limitation may not allow 

for sufficient volumes of CO2 to be transmitted away from the well and into the injection 

formation. EPA acknowledges that there may be circumstances where a lower pressure limitation 

may be appropriate; in such cases, the Director has the authority, at §146.88, to set a lower 

pressure limit in the operating permit. EPA believes that the 90 percent requirement allows the 

consideration of site-specific circumstances and provides a satisfactory margin of safety during 

well operation. 

EPA clarifies that injection pressure limit for each GS project will be based on site-specific 

conditions, and be informed by data on the injection and confining zones. During injection, the 

pressure in the injection zone must not exceed 90 percent of the fracture pressure of the injection 

zone, as specified at §146.88(a). The fracture pressure (and, therefore, the injection pressure) are 

based on site-specific geologic and geomechanical data collected during the site characterization 

process required at §146.82. Tests are available and have been used by injection well operators, 

e.g., Class I operators, to measure fracture pressure. Examples include the step-rate test, in-situ 

stress tests, and a combination of a long spaced sonic log with laboratory measurement of the 

mechanical properties of cores. To meet the GS requirements, the permitting authority must set 

the injection pressure limit at 90 percent of this value. 

The Director will review geologic, hydrogeologic, and geomechanical information submitted by 

the owner or operator in setting permit conditions. If, based on this information, a lower pressure 

limitation is appropriate, the Director has the authority to set a lower limit in the operating 

permit. EPA clarifies that fracturing of the confining zone during injection and/or stimulation is 

also prohibited at §146.88(a). 

The final rule provides for the use of stimulation. EPA believes that stimulation is important for 

enhancing formation injectivity, provided it is performed in a manner that maintains the integrity 

of the confining zone. All stimulation must be approved by the Director. Owners or operators 

must submit a proposed stimulation program as part of the permit application under 

§146.82(a)(9); the plan must demonstrate that any stimulation activities will not compromise the 

integrity of the confining zone. The Director will evaluate the owner or operator's proposed 

stimulation plan in the context of all information about the site, and the owner or operator must 

perform stimulation only as approved. 

EPA is developing guidance on site characterization for GS projects to assist owners or operators 

in meeting the requirements of §146.82 and to assist directors in evaluating permit applications. 

The guidance will describe recommended approaches for characterizing the regional geology and 

hydrogeology of a proposed site and performing the necessary geochemical, geomechanical, and 

geophysical analyses of the injection and confining zone. EPA is also developing guidance for 

primacy agencies that will include recommended approaches for evaluating owner or operatorsubmitted data in setting permit conditions. The guidance will be available on EPA's web site, at 

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

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Letter ID: 0272 Comment ID: 24079 Letter Lines: 215 to 271 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

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

Comment: D. Closure 

[FR p. 43540, §146.93(b)] EPA has proposed an arrangement whereby the operator 

continues to monitor the site for a minimum of 50 years after the cessation of 

injection, unless the operator can demonstrate to the satisfaction of the 

Director that the project no longer poses an endangerment to USDWs and that the 

CO2 plume and pressure front have stabilized. 

While 50 years is not a number that will apply in all cases and projects, we do 

believe that it is appropriate as a default at today’s level of our 

understanding and operational experience with GS. The option that operators have 

under the current proposal to obtain approval for a lower number, based on 

actual project performance, should be sufficient to deal with situations where 

50 years can be demonstrated to be unnecessarily long. Along the same lines, 

there might be situations where 50 years would not suffice, and where the 

Director should require a longer period, as per the current proposal. In 

assessing non-endangerment to USDWs and plume/pressure front stabilization, we 

believe that the EPA should be far more specific in its requirements. We offer 

the following language as a suggested revision to §146.93(b): 

"(b) The owner or operator shall monitor the site following the cessation of 

injection. 

(1) The owner or operator shall continue to conduct monitoring as specified in 

the Director-approved post-injection site care and site closure plan for at 

least 50 years following the cessation of injection or until closure is 

authorized. 

(2)If the owner or operator can demonstrate to the satisfaction of the Director 

before 50 years, based on/pursuant to the criteria in (b), that the geologic 

sequestration project does not and is not expected to pose an endangerment to 

USDWs or result in releases to the atmosphere, the Director may approve an 

amendment to the post-injection site care and site closure plan to reduce the 

frequency of monitoring or may authorize site closure before the end of the 50- 

year period. 

(3) Prior to authorization for site closure, the owner or operator must 

demonstrate to the Director, based on monitoring, other site-specific data, and 

modeling that is consistent with site performance, that no additional monitoring 

is needed to assure that the geologic sequestration project does not and is not 

expected to pose an endangerment to USDWs or any release to the atmosphere. The 

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owner or operator must demonstrate, based on the current understanding of the 

site, including monitoring data and modeling, all of the following: (i) the 

magnitude and extent of the project footprint (CO2 plume and the area of 

elevated pressure); (ii) the location of the detectable CO2 plume; (iii) that 

there is no significant leakage of either CO2 or displaced formation fluids that 

is endangering USDWs or creating a potential release to the atmosphere; (iv) 

that the injected or displaced fluids are not expected to migrate in the future 

in a manner that encounters a potential leakage pathway into a USDW or to the 

atmosphere; (v) that the injection wells at the site completed into or through 

the injection zone or confining zone are plugged and abandoned in accordance 

with these requirements; and (vi) any remaining project monitoring wells at the 

site are being managed by a person and in a manner acceptable to the Director. 

(4) If such a demonstration cannot be made after the 50-year period, the owner 

or operator must submit to the Director a plan to continue post-injection site 

care." 

Individual Response: EPA agrees that a 50 year post-injection site care timeframe represents a 

reasonable and protective post-injection site monitoring period for most projects and available 

data, including data submitted by commenters, do not support a different default timeframe. EPA 

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

and evaluation of public comments. 

However, EPA recognizes that there may be sites where the 50 year post injection site care 

timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. 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 however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in most cases. The default 50 year post-injection site 

care timeframe represents a reasonable and protective monitoring period based on a review of 

research studies, industry reports, and existing environmental programs, and evaluation of public 

comments. 

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

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

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

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

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

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

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

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impacts. 

In response to comments to be more specific, EPA believes §146.93 is sufficiently specific for 

the purposes of protecting USDWs. Furthermore, the commenter’s proposed language regarding 

released CO2 emissions into the air are outside the scope of this rulemaking and EPA’s authority 

under the SDWA. 

Letter ID: 0272 Comment ID: 24080 Letter Lines: 274 to 285 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: In addition, given the desired permanent nature of CO2 sequestration in the 

subsurface and the importance to the public of ensuring long-term attention to 

oversight of project sites, EPA should adopt provisions to assure long-term 

stewardship of GS repositories. This framework should designate an entity with 

responsibility for monitoring and managing sites after closure has been 

authorized. The proposed rule authorizes operators to stop monitoring, but does 

not provide for the stewardship of sites following closure. This needs to be 

rectified by EPA. The agency should consider its authority not just under the 

Safe Drinking Water Act, but also under the Clean Air Act to provide the 

required stewardship framework. It is important that the post-closure framework 

include financing provisions that avoid hidden subsidies for private sector 

operators and are adequate to ensure proper site stewardship in the long-term. 

Individual Response: 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, the financial instrument required under §146.85 will be released if 

it has not been 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, if the Director relied on erroneous information 

provided by the owner or operator when approving site closure. Additionally, an owner or 

operator may always be subject to any action the Administrator deems necessary to protect the 

health of persons under §1431 of the SDWA after site closure if there is unanticipated migration 

towards or into a USDW that causes or threatens imminent and substantial endangerment to 

public health. The action may include issuing administrative orders or commencing a civil action 

for appropriate relief. 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. 

The Agency clarifies that Class VI well permits may be transferred to another owner or operator 

pursuant to §144.38, whereby all other regulatory responsibilities are transferred, including all 

potential liabilities associated with meeting the requirements of that permit. Please see further 

clarification on the issue of long term liability in the preamble of the final rule. 

After site closure an owner or operator may remain liable under tort and other remedies, or under 

other federal statutes including Clean Air Act, 42 U.S.C. §§ 7401-7671; CERCLA, 42 U.S.C. § 

9
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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 approach. 

Comments related to EPA’s authority under the Clean Air Act are outside the scope of the GS 

regulation.