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.
BUREAU OF WATER – GEOLOGY SECTION

CURTIS STATE OFFICE BUILDING, 1000 SW JACKSON ST., STE. 420, TOPEKA, KS 66612-1367

Voice 785-296-5524 Fax 785-296-5509 Web http://kdheks/gov/geo

KANSAS DEPARTMENT OF HEALTH & ENVIRONMENT COMMENTS ON THE 

ENVIRONMENTAL PROTECTION AGENCY PROPOSED FEDERAL 

REQUIREMENTS UNDER THE UNDERGROUND INJECTION CONTROL 

PROGRAM FOR CARBON DIOXIDE GEOLOGIC SEQUESTRATION WELLS –

Proposed Regulations Published in the July 25, 2008, Federal Register Notice

Docket #: EPA-HQ-OW-2008-0390

Prepared by Michael H. Cochran, Chief of the Geology Section

September 29, 2008

General Comments:

We believe the following issues warrant additional review by the Environmental Protection 

Agency:

1. The potential negative impact to large CO2 deep saline formation geologic sequestration 

projects resulting from the reference in these regulations to storage rather than disposal, 

implying the CO2 may have value or is even actually a commodity. Large projects could 

have a CO2 plume covering many square miles. The reference to storage may result in 

the operator having to rent or pay for the use of pore space for storage, which may

involve dealing with numerous parties, considerable legal work and considerable costs. 

2. The potential adverse impact to Class I industrial waste disposal well program that could 

result from the concept of storage described in above item #1. 

3. There is much that needs to be understood about the behavior of CO2 sequestered in 

geologic formations. Additional research is needed to evaluate and determine this impact. 

This includes obtaining a much better understanding of the geochemistry involved, 

plume movement, plume tracking methods and plume fate. 

4. The establishment of the precedence of developing a new well class when a unique or 

unusual well type is encountered. We believe the existing well classification framework 

can address this well type, thus simplifying administration of this type of well. 

5. Consider developing regulations that actually address an injection/withdrawal type 

project much similar to a natural gas porosity storage system. In this scenario the CO2 is 

contained in a limited, defined geologic trap and the system is designed to inject the CO2 

or withdraw the CO2 as needed. 

6. The practicality and appropriateness of liability staying with the owner/operator for an 

extended period of time. Should instead, some form of a Federal/Industry partnership be 

implemented to address this issue, especially since this technology is being pushed at a 

national level as a significant method for reducing CO2 releases to the atmosphere?
BUREAU OF WATER – GEOLOGY SECTION

CURTIS STATE OFFICE BUILDING, 1000 SW JACKSON ST., STE. 420, TOPEKA, KS 66612-1367

Voice 785-296-5524 Fax 785-296-5509 Web http://kdheks/gov/geo

Page 2 of 6

KDHE Comments

EPA CO2 Regulations

September 16, 2008

Potential costs and legal issues in regards to long term liability could limit the number of 

projects implemented.

7. Adequate funding must be provided by EPA to the states so the states can properly 

administer these wells in a protective manner. This is new, additional work for the states 

that EPA is responsible for funding. Current funding provided by EPA does not 

adequately cover the costs of existing state UIC programs, let alone this additional work. 

Comments on Specific Regulations:

144.1, 146.6, 

144.15: Same comment as for item # 4 under the general comments. 

144.18: Should be reworded along the lines of: upon the effective date of these 

regulations, new Class V wells must obtain a permit prior to construction.

144.36: We believe it would be prudent to limit the life of the permit so that 

necessary adjustments to the permit can be made as needed with the 

opportunity for public comment and to establish a process for obtaining 

updated information concerning the injection operation. We would 

recommend a permit life of no more than 10 years. 

144.80, 146.5: Same as for144.1, 146.6 , 144.15. 

144.81: The quality of the injection stream in regards to a minimum concentration 

of CO2 should be established to ensure that it is actually a CO2 

sequestration project and to limit the injection of other harmful or 

undesirable gases. 

For the definition of AoR it needs to be realized that the AoR could be 

quite sizeable potentially covering many square miles. We suggest using 

the criteria for the AoR as found in existing 146.6 and for the Pressure 

Front definition. Otherwise, the AoR as defined could make it impractical 

to accomplish the work required. 

For Geologic Sequestration Project definition, our comments for the AoR 

definition apply also.

146.82 (b): This will be an onerous task based on the proposed definition of AoR. Not 

necessary if the pressure front is calculated or determined. 
BUREAU OF WATER – GEOLOGY SECTION

CURTIS STATE OFFICE BUILDING, 1000 SW JACKSON ST., STE. 420, TOPEKA, KS 66612-1367

Voice 785-296-5524 Fax 785-296-5509 Web http://kdheks/gov/geo

Page 3 of 6

KDHE Comments

EPA CO2 Regulations

September 16, 2008

146.82 (g): Needs to list the formations for which baseline geochemical data should 

be obtained. In addition to the USDWs, this at minimum should include 

the injection formation and the confining zone immediately above the 

injection zone.

146.83 (a): Need to include without initiating or propagating fractures in the injection 

in addition to the confining zone. 

146.83 (b): This should not be an option, but should be required of the 

owner/operator. This is important in evaluating and demonstrating 

containment. 

146.84 (c)(1): The CO2 plume will never cease moving. Even deep formations have a 

natural flow gradient. There will also likely be movement due to density 

gradients and diffusion. 

146.85: Specifics need to be listed for providing acceptable financial 

responsibility. We recommend that the financial test mechanism not be 

allowed for use. This is a very weak mechanism and an operator’s 

financial condition can change quickly. With the financial test there may

be nothing tangible available to cover the costs of plugging, closure and 

post-closure care. 

146.86(b)(2): Some flexibility should be considered on the amount if surface casing 

required because of the many protective testing and monitoring 

requirements and the multilayer protection system provided by the 

requirement of tubing and packer and the longstring being cemented 

bottom to surface. Setting the surface casing through the USDW in some 

areas may not be practical due to the considerable depth. As an alternative, 

we recommend that surface casing be set through the deepest water 

bearing zone that is currently used for a water supply.

146.86 (b)(3): KDHE strongly supports the requirement to cement the longstring casing 

from the bottom of the casing to the surface. This provides at a reasonable 

cost corrosion protection of the casing, prevents undesirable migration of 

fluids behind the casing, provides support to the casing and adds another 

layer of protection of the public health, safety and environment. 
BUREAU OF WATER – GEOLOGY SECTION

CURTIS STATE OFFICE BUILDING, 1000 SW JACKSON ST., STE. 420, TOPEKA, KS 66612-1367

Voice 785-296-5524 Fax 785-296-5509 Web http://kdheks/gov/geo

Page 4 of 6

KDHE Comments

EPA CO2 Regulations

September 16, 2008

146.87 (b): Should include the stipulation for new wells only that new casing shall be 

used. This ensures the proper casing is used and is cheap insurance. Also 

gives a good baseline to start with. 

146.87 (a)(2)(i): Need to also require a gamma log. This is an inexpensive log to conduct 

and provides good information on the type of formations encountered. 

146.87 (a)(2)(ii): Should also allow the option of using cement evaluation logs, which may

actually be superior to the cement bond log in many situations. The 

cement evaluation log provides a 360-degree map of the cement and can 

actually show the orientation and extent of channeling. 

146.87 (a)(3)(ii): Again, should allow the option of using cement evaluation logs, which 

may actually be superior to the cement bond log in many situations. Also, 

should require an initial casing inspection log to establish baseline casing 

conditions, especially since corrosion is a concern in this type of well and

then conduct periodic casing inspection logs to monitor corrosion. We do 

not see a need for the temperature log if the purpose is to determine the 

top of the cement. We do see some benefit to conducting the log to 

establish the baseline temperature gradient in the well.

146.87 (a)(4)(i): We recommend not allowing the use of a gas for conducting the annulus 

pressure test. Based on our experience, gas is not a sensitive test medium 

due to its significant compressibility. A liquid provides an extremely

sensitive test because of its incompressibility and should be the fluid of 

choice for such an important test. 

146.87 (b): The submittal of the cores to the Director is not practical and should not be 

a requirement. What the Director needs is the core report with the test

results. The operator should be required to first submit a coring plan to the 

Director listing the interval to be cored, the coring procedures, the tests to 

be conducted and proposed storage of the core for review and 

consideration of approval by the Director. A core report, including the test 

results and the geomechanical characteristics and values determined such 

as fracture gradient shall be submitted to the Director. The requirement for 

the core itself could be that the core shall be made available for inspection 

by the Director upon the request of the Director. 
BUREAU OF WATER – GEOLOGY SECTION

CURTIS STATE OFFICE BUILDING, 1000 SW JACKSON ST., STE. 420, TOPEKA, KS 66612-1367

Voice 785-296-5524 Fax 785-296-5509 Web http://kdheks/gov/geo

Page 5 of 6

KDHE Comments

EPA CO2 Regulations

September 16, 2008

146.88 (a): The injection pressure/gradient should be determined based on the site 

geology, hydrogeology and geomechanics. KDHE’s “rule of thumb” is 

that injection pressure not exceed a gradient of 0.75 psi/foot of depth. This 

provides a safety factor. The 0.90 gradient is too high in our opinion and 

does not allow much of a safety factor in many cases. 

146.88 (c): The annulus should be filled with a non-corrosive liquid and the word 

fluid should not be used. A fluid can be a gas, liquid, sludge or semisolid 

or other material that flows or moves. For the sensitivity needed to 

monitor for leakage, the annulus should therefore be a liquid. 

146.88 (e): We recommend a Supervisory Control and Data Acquisition (SCADA) 

system be used. This system also allows for monitoring and data trending

to detect anomalies or potential problems before they occur. The system 

can also be programmed to automatically shut-in valves and to alarm 

based on certain parameter values. This system should also be tied to a 

CO2 detector to alarm and shut the well in should CO2 above a certain 

level be detected at the surface. 

146.89 (b): Should include also the requirement for an annual annulus pressure MIT 

using an approved liquid. This MIT should stress the system and be at a 

pressure above the normal operating pressure so that potential problems 

are identified by the test, thus the problem is prevented from occurring 

during operation of the well

146.89 (c) (3): The casing inspection log (CIL) does not detect fluid movement behind 

the casing and should not be listed here. This is an excellent log for 

detecting corrosion problems and the degree of corrosion casing 

inspection logs conducted periodically is a good method for monitoring 

corrosion in the well. Annual testing is excessive in our opinion. Could 

require this annually for say for the first three years and then go to once 

every five year interval if approved by the Director. How would the 

temperature log work or be implemented for this test? Is this based on the 

concept that should the CO2 migrate upwards behind the casing that it will 

de-pressure and flash to a gas causing a measurable temperature anomaly?

Or, is the concept that the well is shut-in for a time period and then a 

calculated amount of CO2 injected. Then injection is ceased and a series 

of shut-in temperature logs conducted and a composite of the shut-in logs 

is then analyzed to track upwards migration of CO2?
BUREAU OF WATER – GEOLOGY SECTION

CURTIS STATE OFFICE BUILDING, 1000 SW JACKSON ST., STE. 420, TOPEKA, KS 66612-1367

Voice 785-296-5524 Fax 785-296-5509 Web http://kdheks/gov/geo

Page 6 of 6

KDHE Comments

EPA CO2 Regulations

September 16, 2008 

146.90 (g): We believe there are few, if any indirect methods that will work or that 

can feasibly be used to monitor the plume location. This is based on our 

experience with some of these methods on other projects. For example, 

with micro-gravity the difference in values or readings would most likely

be so small that these would probably be less than the measurement error 

of the equipment. There has to be a significant difference in density to 

measure the difference in gravity. 

146.91: We believe this should be monthly reporting. This is information that is 

important and needs to be reviewed at a frequency by the regulatory

agency to ensure problems are identified and addressed in a timely 

manner. Think about this for example - quarterly reporting for say the 

third calendar quarter results in data that is collected July 1, 2008, would 

not be seen by the regulatory agency before October 30, 2009, if the 

operator is allowed say 30 days after the end of the quarter to provide the 

report. Is that reasonable or appropriate? 

The timeframe for submittal of the quarterly report should be stated.

146.92 (a): We believe the sequence of work listed is not appropriate. The bottom 

hole pressure should be determined prior to flushing the well to obtain a 

more accurate reading. 

146.93 (b) (3): Plume stabilization needs to be clarified as to what this means. The plume 

will never be completely stabile. The CO2 plume will continue to move by 

a combination of methods including density differences, natural formation 

flow gradients and diffusion. Recommend dropping the reference to the 

plume or pressure front having stabilized.

146.93 (f): This will be impractical for large sequestration projects due to the 

paperwork and legal work to deal with a significant number of parties. 
Letter ID: 0108 

Commenter: Michael H. Cochran 

Organization: Bureau of Water, Division of Environment, Kansas Department of Health & 

Environment (KDHE) 

Letter ID: 0108 Comment ID: 21942 Letter Lines: 15 to 28 

Comment Code: 1210 1.1.1 Comments about the proposed rule 

Comment Code: 1310 1.1.2.4 Comments on other "out of scope" issues, e.g., pore space 

ownership 

Comment: We believe the following issues warrant additional review by the 

Environmental Protection Agency: 

1. The potential negative impact to large CO2 deep saline formation geologic 

sequestration projects resulting from the reference in these regulations to 

storage rather than disposal, implying the CO2 may have value or is even 

actually a commodity. Large projects could have a CO2 plume covering many square 

miles. The reference to storage may result in the operator having to rent or pay 

for the use of pore space for storage, which may involve dealing with numerous 

parties, considerable legal work and considerable costs. 

2. The potential adverse impact to Class I industrial waste disposal well 

program that could result from the concept of storage described in above item 

#1. 

Individual Response: EPA acknowledges that issues such as pore space ownership and surface 

and subsurface property rights are important issues that need to be addressed; however, these are 

generally addressed though state regulations and are outside of the UIC program’s authority 

under the Safe Drinking Water Act (SDWA). EPA adds that the requirements apply to owners or 

operators of injection wells used to inject CO2 for permanent storage, and do not apply to 

owners or operators of Class I wells. 

EPA believes that developing a consistent regulatory framework will ensure that there is 

adequate opportunity for public involvement on the permitting process and that all USDWs are 

protected from endangerment. 

Letter ID: 0108 Comment ID: 21943 Letter Lines: 30 to 34 

Comment Code: 1510 1.2.2.3 Need for additional study 

Comment: 3. There is much that needs to be understood about the behavior of CO2 

sequestered in geologic formations. Additional research is needed to evaluate 

and determine this impact. This includes obtaining a much better understanding 

of the geochemistry involved, plume movement, plume tracking methods and plume 

1
fate. 

Individual Response: EPA agrees that continued research in all GS associated fields will be 

integral to development of GS technology. EPA is aware of research by other federal agencies, 

industry, international parties, and academia related to GS, including projects that address many 

of the topics suggested by commenters. EPA published a Notice of Data Availability (NODA) 

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

the results of research at three DOE partnership sites (in Escatawpa, Mississippi; the Aneth Field 

in Paradox Basin, southeast Utah; and the Pump Canyon Site, New Mexico). In the NODA and 

Request for Comment, EPA also described two studies by the Lawrence Berkeley National 

Laboratory on the potential effects of CO2 injection on ground water and surrounding formations 

to determine the potential for impacts on USDWs and human health in the event that a GS 

project is not properly sited, operated, or managed. 

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

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

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

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

requirements are appropriate or necessary. 

Letter ID: 0108 Comment ID: 21944 Letter Lines: 36 to 39 ; 63 to 63 ; 74 to 74 

Comment Code: 2040 1.5.2 Oppose Class VI designation 

Comment: 4. The establishment of the precedence of developing a new well class when a 

unique or unusual well type is encountered. We believe the existing well 

classification framework can address this well type, thus simplifying 

administration of this type of well. 

144.1, 146.6, 144.15: Same comment as for item # 4 under the general comments. 

144.80, 146.5: Same as for144.1, 146.6 , 144.15. 

Individual Response: EPA disagrees that the existing well class classification can address 

injection of CO2 for long-term storage because there are significant differences between how 

projects are operated, as well as the risks posed by these different injection activities. The new 

tailored approach of the GS rule is designed to address the general risks deep injection may pose 

to USDWs and is tailored specifically to address the risks posed by long-term storage of CO2 

(i.e., very large volumes, very long time-periods, and reservoir pressure conditions). 

Letter ID: 0108 Comment ID: 21945 Letter Lines: 41 to 44 

Comment Code: 2000 1.5 Need for a New Class of Injection Well 

Comment Code: 2140 1.6.2 Depleted oil and gas reservoirs 

Comment Code: 2146 1.6.2.2 Comments opposing injection into depleted reservoirs 

2
Comment: 5. Consider developing regulations that actually address an injection/withdrawal 

type project much similar to a natural gas porosity storage system. In this 

scenario the CO2 is contained in a limited, defined geologic trap and the system 

is designed to inject the CO2 or withdraw the CO2 as needed. 

Individual Response: EPA clarifies that the GS rule addresses injection wells designed for longterm sequestration of carbon dioxide; the Class VI designation and permit requirements are not 

applicable to owners or operators that plan to withdraw carbon dioxide. 

The Agency believes that the nature and risks of CO2 injection for the primary purpose of longterm storage poses unique risks that may endanger USDWs, and therefore has developed new 

Class VI regulations to address these risks. Furthermore, the GS requirements adequately address 

these risks. 

Letter ID: 0108 Comment ID: 21947 Letter Lines: 55 to 59 

Comment Code: 5600 2.11 Comments related to UIC Program primacy for Class VI wells 

Comment: 7. Adequate funding must be provided by EPA to the states so the states can 

properly administer these wells in a protective manner. This is new, additional 

work for the states that EPA is responsible for funding. Current funding 

provided by EPA does not adequately cover the costs of existing state UIC 

programs, let alone this additional work. 

Individual Response: EPA acknowledges that there may be technical and administrative 

challenges including resource concerns, and will work closely with the States to assist them in 

resolving funding issues or acquiring the resources, personnel, and training needed to address the 

unique technical challenges associated with GS. 

EPA will also incorporate Class VI wells into the UIC Program's grant allocation process. The 

States/Tribes/Territories must also demonstrate that they have adequate resources to implement 

the program through matching resources against those allocated by the UIC Program's grant 

allocation formula. Currently, primacy programs are required to meet a minimum of 25 percent 

matching requirement. 

Letter ID: 0108 Comment ID: 21957 Letter Lines: 46 to 53 

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

Comment: 6. The practicality and appropriateness of liability staying with the 

owner/operator for an extended period of time. Should instead, some form of a 

Federal/Industry partnership be implemented to address this issue, especially 

since this technology is being pushed at a national level as a significant 

3
method for reducing CO2 releases to the atmosphere? 

Potential costs and legal issues in regards to long term liability could limit 

the number of projects implemented. 

Individual Response: Under the final GS rule, once an owner or operator has met all regulatory 

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

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

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

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

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

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

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

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

operator when approving site closure. 

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

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

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

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

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

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

the health of such persons. The action may include issuing administrative orders or commencing 

a civil action for appropriate relief against the owner or operator of a Class VI well. If the owner 

or operator fails to comply with the order, they may be subject to a civil penalty for each day in 

which such violation occurs or failure to comply continues. 

Furthermore, after site closure an owner or operator may remain liable under tort and other 

remedies, or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. 

§§ 7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. Please 

note that EPA does not have authority to transfer SDWA or other legal liability for Class VI 

wells to the State or federal government or a third-party fund. See the final rule preamble for 

further discussion of EPA's final approach. 

EPA notes that under SDWA, EPA has the general authority to set financial responsibility 

requirements for injection well owners or operators to ensure that adequate resources are 

available to protect USDWs throughout the life of the GS project. However, this authority does 

not extend to allowing the Agency to create a financial instrument with EPA as the trustee. 

Furthermore, EPA does not have authority in the SDWA to create a trust fund. The Agency 

clarifies that the trust funds that are addressed as financial responsibility instruments through the 

GS rule are set up by individual owners or operators and are different from a national-level trust 

described by the commenters that would cover large numbers of GS projects. 

Letter ID: 0108 Comment ID: 21959 Letter Lines: 65 to 66 

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

4
Comment Code: 2048 1.5.2.4 Oppose Class VI/ Support Class V experimental technology well 

Comment: 144.18: Should be reworded along the lines of: upon the effective date of these 

regulations, new Class V wells must obtain a permit prior to construction. 

Individual Response: EPA clarifies that any owner or operator seeking to construct an injection 

well must obtain a permit before beginning injection, but not necessarily the construction of the 

well. Owners and operators of Class VI wells for long-term sequestration or Class V 

experimental technology wells (for experimental GS projects) must submit information about the 

well, the geology of the site, and the planned injection to demonstrate to the Director that the 

project will be operated in a manner that protects USDWs from endangerment. 

Letter ID: 0108 Comment ID: 21960 Letter Lines: 76 to 79 

Comment Code: 1614 1.3.1.2 Impurities in captured CO2; purity standards for CO2 

Comment: 144.81: The quality of the injection stream in regards to a minimum 

concentration of CO2 should be established to ensure that it is actually a CO2 

sequestration project and to limit the injection of other harmful or undesirable 

gases. 

Individual Response: The GS rule does not set generic purity standards for CO2 injectate 

streams (e.g., a percent CO2). Instead, the GS rule addresses the quality and quantity of 

impurities by requiring owners or operators to submit information on the source of the CO2 and 

its physical and chemical properties. Specifically, the GS rule requires the owner or operator to 

submit data about the site, including an analysis of the chemical and physical characteristics of 

the CO2 stream, as required at §146.82(a)(7)(iv), and information on the compatibility of the 

CO2 stream with fluids in the injection zone and minerals in both the injection and the confining 

zones and the materials used to construct the well, per §146.82(c)(3). This information can help 

the Director determine the potential for geochemical reactions between the injectate (CO2) and 

the host geologic formations, which could result in the plugging of pore spaces or the dissolution 

of formation minerals. 

Since the GS rule, at §146.81(d), prohibits the injection of CO2 streams that meet the definition 

of a hazardous waste under 40 CFR part 261, injection of a CO2 stream that is determined to be a 

hazardous waste may only occur in a Class I hazardous waste injection well. 

Letter ID: 0108 Comment ID: 21961 Letter Lines: 81 to 88 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling CO2 movement 

Comment: For the definition of AoR it needs to be realized that the AoR could be quite 

sizeable potentially covering many square miles. We suggest using the criteria 

for the AoR as found in existing 146.6 and for the Pressure Front definition. 

5
Otherwise, the AoR as defined could make it impractical to accomplish the work 

required. 

For Geologic Sequestration Project definition, our comments for the AoR 

definition apply also. 

Individual Response: The Agency has carefully considered all comments on the AoR definition 

at 146.84(a) and modified it to read as follows: The region surrounding the geologic 

sequestration project where USDWs may be endangered by the injection activity. The area of 

review is delineated using computational modeling that accounts for the physical and chemical 

properties of all phases of the injected CO2 stream and is based on available site 

characterization, monitoring, and operational data. 

Letter ID: 0108 Comment ID: 21962 Letter Lines: 90 to 91 

Comment Code: 1230 1.1.1.2 General comments on the regulatory text 

Comment: 146.82 (b): This will be an onerous task based on the proposed definition of 

AoR. Not necessary if the pressure front is calculated or determined. 

Individual Response: EPA acknowledges the comment. For additional information on EPA's 

final regulatory approach, please see the final rule and preamble as well as the rulemaking 

docket. 

Letter ID: 0108 Comment ID: 21963 Letter Lines: 93 to 95 

Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment: 146.82 (g): Needs to list the formations for which baseline geochemical data 

should be obtained. In addition to the USDWs, this at minimum should include the 

injection formation and the confining zone immediately above the injection zone. 

Individual Response: The GS regulation, at §146.82(a)(6), requires the owner or operator to 

submit baseline geochemical data on subsurface geologic formations. EPA is not specifying for 

which formations this information should be submitted to allow flexibility, but examples may 

include the following formations: a) the injection zone, b) the confining zones, c) containment 

zones above the confining zones in which any potentially migrating CO2 could be trapped, d) all 

USDWs, and e) any other geologic zone or formation that is important to the proposed 

monitoring program. The Director has the authority to request additional geochemical data as 

well. 

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

and Directors in evaluating permit requirements and applications under §146.82. The guidance 

provides recommendations regarding characterizing the regional geology and hydrogeology of a 

6
proposed GS site as well as performing the necessary geochemical, geomechanical, and 

geophysical analyses of the injection and confining zone. The guidance can be found on EPA’s 

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

Letter ID: 0108 Comment ID: 21964 Letter Lines: 97 to 98 

Comment Code: 3110 2.1.1 Proposed siting requirements (i.e., injection/confining zones, 

trapping mechanism) 

Comment: 146.83 (a): Need to include without initiating or propagating fractures in the 

injection in addition to the confining zone. 

Individual Response: EPA acknowledges the importance of selecting GS sites with confining 

zones that are free of transmissive faults and fractures but disagrees that the rule should prohibit 

fracturing within the injection zone. EPA believes that, in some circumstances, fracturing is 

necessary (i.e., in association with an approved stimulation program) to improve wellbore and 

formation injectivity. EPA clarifies that all stimulation for GS must be reported to the Director 

for approval 30 days in advance of such activities, pursuant to requirements at §146.91(d)(2). 

Letter ID: 0108 Comment ID: 21969 Letter Lines: 100 to 101 

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones 

(seeking comment) 

Comment: 146.83 (b): This should not be an option, but should be required of the 

owner/operator. This is important in evaluating and demonstrating containment. 

Individual Response: EPA agrees with commenters that, in some situations, the presence of 

additional confining and containment zones above the primary (i.e., lowermost) confining zone 

can improve USDW protection from endangerment. The final regulation retains the requirement 

at §146.83(b) which affords the Director discretion to require owners or operators to identify and 

characterize additional zones. 

Letter ID: 0108 Comment ID: 21970 Letter Lines: 103 to 105 

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling CO2 movement 

Comment: 146.84 (c)(1): The CO2 plume will never cease moving. Even deep formations have 

a natural flow gradient. There will also likely be movement due to density 

gradients and diffusion. 

Individual Response: EPA agrees with the commenter that there may be cases where movement 

of the CO2 plume will never cease due to gradient, diffusion, and density gradients; however, 

7
EPA believes that plume movement may stabilize at a point where movement of the CO2 plume 

slows or pressures in the injection zone sufficiently decline to the point that they no longer pose 

an endangerment to USDWs. EPA believes that in all cases, these criteria will be met at some 

point after the cessation of injection. As discussed in the preamble to the proposed GS regulation 

and the associated background document, "Computational Modeling of Underground Injection of 

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

Sources of Drinking Water" (cited in the proposed rule preamble as USEPA, 2008d), research 

has shown that CO2 may continue to migrate for a period of time after injection ceases. 

For this reason, the GS regulation does not specify a timeframe over which the AoR delineation 

model should run. Rather, the model should be used to predict the ultimate plume movement up 

to the point the plume movement ceases or pressures in the injection zone sufficiently decline to 

the point that they no longer pose an endangerment to USDWs. 

Letter ID: 0108 Comment ID: 21971 Letter Lines: 107 to 111 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: 146.85: Specifics need to be listed for providing acceptable financial 

responsibility. We recommend that the financial test mechanism not be allowed 

for use. This is a very weak mechanism and an operator’s financial condition can 

change quickly. With the financial test there may be nothing tangible available 

to cover the costs of plugging, closure and post-closure care. 

Individual Response: The final GS rule specifies qualifying financial responsibility instruments 

at §146.85(a)(1). EPA has clarified the financial responsibility requirements by: 

1) Describing “qualifying instruments” to cover the cost of corrective action, injection well 

plugging, PISC and site closure, and emergency and remedial response in a manner that prevents 

endangerment of USDWs. 

2) Adding language clarifying that the financial responsibility instrument is directly enforceable 

regardless of whether the requirement is a condition of the permit. 

3) Requiring submission of annual inflationary updates and specifying a 60-day timeframe after 

notification by the Director for the submission of written updates of adjustments to the cost 

estimate. 

4) Requiring owners or operators to notify the Director no later than 10 days after filing for 

bankruptcy. 

EPA adds that owners or operators will have the flexibility to use instruments for specific 

activity in a project, but if the use of a financial test is not appropriate to ensure that resources 

will be available over the long term, the Director will have the discretion to not allow financial 

tests as a financial responsibility instrument for PISC and closure. 

EPA is developing guidance that will provide more information about the types of financial 

instruments owners or operators can use to meet their financial responsibility requirements for 

Class VI wells. The guidance will also assist Directors in evaluating financial responsibility 

8
demonstrations. 

EPA is retaining the financial test as an option to demonstrate financial responsibility for Class 

VI wells. EPA believes that, if properly used, the financial test can be an appropriate option for 

some owners or operators. EPA recognizes that it is important for self-insurers to be creditworthy, otherwise USDWs may not be adequately protected. Since there are some concerns 

about the use of financial tests, including those mentioned by the commenter, EPA is developing 

guidance (available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) to assist Directors in 

evaluating the appropriateness of the financial test in specific circumstances. 

Letter ID: 0108 Comment ID: 21972 Letter Lines: 113 to 120 

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment) 

Comment: 146.86(b)(2): Some flexibility should be considered on the amount if surface 

casing required because of the many protective testing and monitoring 

requirements and the multilayer protection system provided by the requirement of 

tubing and packer and the longstring being cemented bottom to surface. Setting 

the surface casing through the USDW in some areas may not be practical due to 

the considerable depth. As an alternative, we recommend that surface casing be 

set through the deepest water bearing zone that is currently used for a water 

supply. 

Individual Response: EPA believes that the regulations allow appropriate flexibility regarding 

the surface casing. The GS rule at §146.86(b)(2) requires that surface casing extend through the 

base of the lowermost USDW and be cemented to the surface through the use of single or 

multiple strings of casing and cement. It does not, however, specify how cementing would be 

accomplished, and gives flexibility to the owner or operator to propose alternate methods that 

provide an amount of cement sufficient to meet the standard that USDWs are protected. 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. 

EPA disagrees that other requirements for Class VI wells, such as tubing and packer or 

monitoring requirements, negate the need for proper surface casing. Each of these measures 

provides a different but necessary level of USDW protection. EPA believes that all of the 

requirements for Class VI wells, working together, provide multiple barriers of protection against 

endangerment of USDWs. 

Letter ID: 0108 Comment ID: 21973 Letter Lines: 122 to 126 

Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment) 

9
Comment: 146.86 (b)(3): KDHE strongly supports the requirement to cement the longstring 

casing from the bottom of the casing to the surface. This provides at a 

reasonable cost corrosion protection of the casing, prevents undesirable 

migration of fluids behind the casing, provides support to the casing and adds 

another layer of protection of the public health, safety and environment. 

Individual Response: EPA acknowledges the comment and agrees that the requirement for 

long-string casing of Class VI wells at §146.86(b) will offer the best protection against fluid 

movement behind the casing, between formations, and above the injection zone and will ensure 

competency of Class VI wells and protect USDWs from endangerment. The buoyant nature of 

CO2 dictates deep well construction procedures that address movement of fluid behind the 

casing and provide necessary barriers to CO2 leakage outside of the injection zone. In 

developing the construction requirements for Class VI wells, EPA reviewed the work cited by 

Carey et al. (2007) and Crow et al. (2008). EPA agrees that they offer important justification for 

the establishment of tailored requirements. 

Letter ID: 0108 Comment ID: 21974 Letter Lines: 128 to 130 

Comment Code: 3820 2.3.1 Well construction procedures 

Comment: 146.87 (b): Should include the stipulation for new wells only that new casing 

shall be used. This ensures the proper casing is used and is cheap insurance. 

Also gives a good baseline to start with. 

Individual Response: Although the rule does not specifically require the use of new casing, 

EPA expects that only new casing will be allowed in the construction of Class VI wells. The GS 

rule at §146.82(a)(7), requires owners or operators to submit information on planned injection 

pressures, which the Director will use in evaluating the proposed casing, tubing, and packer 

design. EPA adds that, in determining the suitability of well materials and the design of the well, 

the Director must consider various aspects of the injection project, including injection pressure, 

external pressure, internal pressure and axial loading in §146.86(b)(1)(ii), corrosiveness of the 

CO2 stream, and formation fluids in §146.86(b)(1)(v). 

Letter ID: 0108 Comment ID: 21975 Letter Lines: 132 to 164 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: 146.87 (a)(2)(i): Need to also require a gamma log. This is an inexpensive log 

to conduct and provides good information on the type of formations encountered. 

146.87 (a)(2)(ii): Should also allow the option of using cement evaluation logs, 

which may actually be superior to the cement bond log in many situations. The 

cement evaluation log provides a 360-degree map of the cement and can actually 

show the orientation and extent of channeling. 

10
146.87 (a)(3)(ii): Again, should allow the option of using cement evaluation 

logs, which may actually be superior to the cement bond log in many situations. 

Also, should require an initial casing inspection log to establish baseline 

casing conditions, especially since corrosion is a concern in this type of well 

and then conduct periodic casing inspection logs to monitor corrosion. We do not 

see a need for the temperature log if the purpose is to determine the top of the 

cement. We do see some benefit to conducting the log to establish the baseline 

temperature gradient in the well. 

146.87 (a)(4)(i): We recommend not allowing the use of a gas for conducting the 

annulus pressure test. Based on our experience, gas is not a sensitive test 

medium due to its significant compressibility. A liquid provides an extremely 

sensitive test because of its incompressibility and should be the fluid of 

choice for such an important test. 

146.87 (b): The submittal of the cores to the Director is not practical and 

should not be a requirement. What the Director needs is the core report with 

the test results. The operator should be required to first submit a coring plan 

to the Director listing the interval to be cored, the coring procedures, the 

tests to be conducted and proposed storage of the core for review and 

consideration of approval by the Director. A core report, including the test 

results and the geomechanical characteristics and values determined such as 

fracture gradient shall be submitted to the Director. The requirement for the 

core itself could be that the core shall be made available for inspection by the 

Director upon the request of the Director. 

Individual Response: Regarding the comment on §146.87(a)(2)(i), EPA believes that a gamma 

log will not always provide better information than resistivity and spontaneous potential logging. 

Gamma logs can provide information on the mineral composition of the formations, but do not 

provide the physical (lithologic and stratigraphic) information available from resistivity and 

spontaneous potential logs. Gamma logs also do not provide information on the formation fluids. 

EPA adds that if the Director determines that a gamma ray log will provide better information on 

the surface casing portion of the well, he/she has authority to require one. 

Regarding the comment on §146.87(a)(2)(ii), EPA clarifies at §146.87(a)(2)(ii) that owners or 

operators must perform a cement bond (i.e., cement evaluation) log after the casing is set and 

cemented. 

Regarding the comment on §146.87(a)(4)(i), EPA disagrees that compressibility of gas would 

yield inaccurate readings for testing the annulus. Pressure testing by liquid or gas is a common 

practice. Compressibility or any other characteristics would be known and could be compensated 

for by calculation. EPA clarifies that pressure testing of the injection well (with liquid or gas) is 

to be performed during the construction phase, not during injection operations. Continuous 

recording of the annulus fluid pressure and volume during injection is required at §§146.88(e) 

and 146.89(b). 

11
Regarding the comment on §146.87(b), EPA clarifies that it is not the Agency's intent that 

physical cores be submitted to the Director. In the final GS rule, EPA has revised the first 

sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or 

sidewall cores of the injection zone and confining system and formation fluid samples from the 

injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that 

includes: well log analyses (including well logs), core analyses, and formation fluid sample 

information...." 

EPA has conducted extensive research and has found that the tests and logs specified at 

§146.87(a) have been proven in industry practice and research to identify cementing flaws. EPA 

adds that these tests are necessary to verify information about the injection and confining zones, 

and ensure that the well is being drilled and cased as approved and has mechanical integrity. This 

information demonstrates that the well can be operated and tested in a manner that will meet the 

requirements for Class VI wells. Should alternative methods be shown to provide equivalent or 

better information, the Director may allow such alternatives under §146.87(a)(5). 

Letter ID: 0108 Comment ID: 21976 Letter Lines: 166 to 170 

Comment Code: 4110 2.4.1.1 Injection pressure limitations 

Comment: 146.88 (a): The injection pressure/gradient should be determined based on the 

site geology, hydrogeology and geomechanics. KDHE’s "rule of thumb" is that 

injection pressure not exceed a gradient of 0.75 psi/foot of depth. This 

provides a safety factor. The 0.90 gradient is too high in our opinion and does 

not allow much of a safety factor in many cases. 

Individual Response: EPA disagrees with the suggestion that injection pressure be set at 75 

percent of fracture pressure. EPA believes that this 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 clarifies that the injection pressure limit for each GS project will be based on site-specific 

conditions, and be informed by data on the injection zone. 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. 

Letter ID: 0108 Comment ID: 21977 Letter Lines: 172 to 175 

12
Comment Code: 4100 2.4.1 Injection parameters 

Comment: 146.88 (c): The annulus should be filled with a non-corrosive liquid and the 

word fluid should not be used. A fluid can be a gas, liquid, sludge or 

semisolid or other material that flows or moves. For the sensitivity needed to 

monitor for leakage, the annulus should therefore be a liquid. 

Individual Response: EPA anticipates, based on the history of injection practices, that owners 

and operators would propose, and Directors would approve, the use of liquids for this purpose. 

Letter ID: 0108 Comment ID: 21978 Letter Lines: 177 to 182 

Comment Code: 4100 2.4.1 Injection parameters 

Comment: 146.88 (e): We recommend a Supervisory Control and Data Acquisition (SCADA) 

system be used. This system also allows for monitoring and data trending to 

detect anomalies or potential problems before they occur. The system can also be 

programmed to automatically shut-in valves and to alarm based on certain 

parameter values. This system should also be tied to a CO2 detector to alarm and 

shut the well in should CO2 above a certain level be detected at the surface. 

Individual Response: To meet the requirements at §146.88(e), Class VI wells will be equipped 

with some type of continuous computer-based monitoring device that will be connected to 

alarms and the shut-off system. EPA does not believe it is necessary to specify what type of 

equipment is to be used to trigger the shut-off system. Instead, the regulation allows the owner or 

operator some flexibility in deciding what equipment and alarms should be installed to allow site 

specific flexibility and to make use of improvements in technology. EPA believes that the 

technology for continuous monitoring is available and is currently in fairly wide use. The 

combination of computer-driven continuous pressure monitoring linked to an automatic injection 

shut-off provides maximum protection of USDWs from endangerment and provides the earliest 

warning to owners or operators that well repairs need to be performed. 

Letter ID: 0108 Comment ID: 21979 Letter Lines: 184 to 188 

Comment Code: 4520 2.5.1 Continuous internal mechanical integrity monitoring (seeking 

comment) 

Comment: 146.89 (b): Should include also the requirement for an annual annulus pressure 

MIT using an approved liquid. This MIT should stress the system and be at a 

pressure above the normal operating pressure so that potential problems are 

identified by the test, thus the problem is prevented from occurring during 

operation of the well 

Individual Response: EPA believes that continuous pressure monitoring to demonstrate internal 

MI at §146.89(b) is superior to an annual annulus pressure MIT. Continuous pressure monitoring 

13
of GS injection wells, instead of periodic testing, which is required for most other types of deep 

injection wells, is necessary given 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, and the temperature and pressure effects associated with injecting 

supercritical CO2. The regulation, at §146.89(e), provides the Director the discretion to require 

an annual annulus pressure MIT in addition to the continuous pressure monitoring to 

demonstrate internal MI; such a periodic pressure test could serve as an additional safeguard. 

Letter ID: 0108 Comment ID: 21980 Letter Lines: 190 to 193 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: 146.89 (c) (3): The casing inspection log (CIL) does not detect fluid movement 

behind the casing and should not be listed here. This is an excellent log for 

detecting corrosion problems and the degree of corrosion casing inspection logs 

conducted periodically is a good method for monitoring corrosion in the well. 

Individual Response: EPA agrees that the casing inspection log is not an appropriate test to 

detect fluid movement behind the casing, but clarifies that it is appropriate for determining the 

presence or absence of corrosion of the long-string casing, and is required if the Director 

determines that it is necessary based on site-specific information. EPA has revised the final GS 

rule to require that the frequency of the casing inspection log be specified in the approved testing 

and monitoring plan. See §146.89(d). For additional information, please see the discussion of 

MITs in the final rule preamble. 

Letter ID: 0108 Comment ID: 21981 Letter Lines: 194 to 196 

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: Annual testing is excessive in our opinion. Could require this annually for say 

for the first three years and then go to once every five year interval if 

approved by the Director. How would the temperature log work or be implemented 

Individual Response: EPA disagrees that the annual mechanical integrity testing is excessive. 

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

injection well external mechanical integrity at least once annually 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. 

14
EPA 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: 0108 Comment ID: 21982 Letter Lines: 196 to 202 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: approved by the Director. How would the temperature log work or be implemented 

for this test? Is this based on the concept that should the CO2 migrate upwards 

behind the casing that it will de-pressure and flash to a gas causing a 

measurable temperature anomaly? Or, is the concept that the well is shut-in for 

a time period and then a calculated amount of CO2 injected. Then injection is 

ceased and a series of shut-in temperature logs conducted and a composite of the 

shut-in logs is then analyzed to track upwards migration of CO2? 

Individual Response: EPA believes that the MITs described in §146.89(c) of the rule (e.g., an 

approved tracer log or temperature or noise logs) are effective methods for demonstrating 

external MI. They are currently used by owners or operators of Class I and Class II wells. The 

Agency notes that the regulations do provide the Director flexibility at §146.89(e) to approve the 

use of alternative MIT methods. They have been used successfully by injection well operators 

for decades and provide an important early warning of potential problems in the injection well 

system. EPA is developing guidance on monitoring and testing to assist owners/operators and 

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

guidance describes available technologies for implementing a testing and monitoring plan, 

including MITs. This guidance will be available on EPA’s website at 

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

EPA is using an adaptive approach to regulating GS. The Agency plans to collect and review 

data every six years on GS projects to determine whether the appropriate amount and types of 

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

modifications to the requirements are appropriate or necessary. 

Letter ID: 0108 Comment ID: 21983 Letter Lines: 204 to 210 

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

comment) 

Comment: 146.90 (g): We believe there are few, if any indirect methods that will work or 

that can feasibly be used to monitor the plume location. This is based on our 

experience with some of these methods on other projects. For example, with 

micro-gravity the difference in values or readings would most likely be so small 

15
that these would probably be less than the measurement error of the equipment. 

There has to be a significant difference in density to measure the difference in 

gravity. 

Individual Response: EPA has revised the final rule at §146.90(g)(2) to require owners or 

operators to track the position of the CO2 plume using indirect methods (e.g., seismic, electrical, 

gravity, or electromagnetic surveys and/or down-hole CO2 detection tools), 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 believes that this approach provides flexibility to develop a site-specific monitoring plan 

and recognizes that indirect techniques are not appropriate in all situations. The owner or 

operator's approved testing and monitoring plan will include the site-specific details, 

technologies, testing and monitoring frequencies, and other pertinent information. 

Letter ID: 0108 Comment ID: 21984 Letter Lines: 212 to 221 

Comment Code: 4760 2.7.6 Proposed reporting frequency (seeking comment) 

Comment: 146.91: We believe this should be monthly reporting. This is information that is 

important and needs to be reviewed at a frequency by the regulatory agency to 

ensure problems are identified and addressed in a timely manner. Think about 

this for example - quarterly reporting for say the third calendar quarter 

results in data that is collected July 1, 2008, would not be seen by the 

regulatory agency before October 30, 2009, if the operator is allowed say 30 

days after the end of the quarter to provide the report. Is that reasonable or 

appropriate? 

The timeframe for submittal of the quarterly report should be stated. 

Individual Response: The final rule remains unchanged from the proposal and requires semiannual reporting of monthly average, maximum, and minimum values for injection pressure, 

flow rate and volume, annular pressure, and monthly annulus fluid volume added at §146.91(a). 

EPA believes that monthly reporting of routine operational data and monitoring results would 

provide no additional protection of USDWs from endangerment. EPA adds that, at §146.91(c), it 

has included in the final rule a requirement that operators must report within 24 hours of any 

event that may endanger USDWs. EPA notes that states seeking primacy for Class VI wells are 

free to require more frequent reporting. For additional information, please see the final rule and 

the preamble for a discussion of EPA's final approach to recordkeeping and reporting. 

16
Letter ID: 0108 Comment ID: 21985 Letter Lines: 223 to 225 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: 146.92 (a): We believe the sequence of work listed is not appropriate. The 

bottom hole pressure should be determined prior to flushing the well to obtain a 

more accurate reading. 146.93 (b) (3): Plume stabilization needs to be 

Individual Response: EPA is retaining the proposed approach to well plugging in the final rule 

at §146.92(a), including the requirement to determine bottomhole reservoir pressure. In addition, 

the injection well plugging plan must include an appropriate test or measure to determine 

bottomhole reservoir pressure. EPA believes that the plugging procedures in the GS rule are 

necessary to ensure the injection well does not become a conduit for future fluid movement that 

could result in endangerment to USDWs. 

Letter ID: 0108 Comment ID: 21986 Letter Lines: 225 to 229 

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

Comment: more accurate reading. 146.93 (b) (3): Plume stabilization needs to be 

clarified as to what this means. The plume will never be completely stabile. The 

CO2 plume will continue to move by a combination of methods including density 

differences, natural formation flow gradients and diffusion. Recommend dropping 

the reference to the plume or pressure front having stabilized. 

Individual Response: EPA clarifies that in the final rule, §146.93(b)(3) no longer requires the 

plume and pressure front to have stabilized. EPA acknowledges that many site-specific factors 

will influence the determination of when the CO2 plume and pressure front no longer pose a risk 

of endangerment to USDWs. It is for this reason that EPA believes that Directors, in consultation 

with operators, will be in the best position to determine whether additional post-injection site 

care is needed. EPA expects this decision to be made based on relevant site data and in 

consultation with all potentially impacted parties. 

EPA agrees that a complete cessation of plume movement may not occur at some sites for long 

time periods due to density differences, natural formation flow gradients, and diffusion. EPA 

clarifies that a complete cessation of plume movement is not required, only a demonstration that 

the plume and pressure front no longer pose a risk of endangerment to USDWs. 

Letter ID: 0108 Comment ID: 21988 Letter Lines: 231 to 232 

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93) 

17
Comment: 146.93 (f): This will be impractical for large sequestration projects due to the 

paperwork and legal work to deal with a significant number of parties. 

Individual Response: EPA disagrees that the owner or operator should not be responsible for 

record retention such as site closure reports. EPA believes that the requirements that the owner or 

operator retain for ten years following site closure, records collected during the post-injection 

site care period at §146.93(f) and §146.93(h) are appropriate for the post-injection and site 

closure period to ensure that data are available to support non-endangerment demonstrations and 

to address any concerns that may arise following site closure. This data will also support EPA's 

review of project data as part of the adaptive rulemaking approach. 

Letter ID: 0108 Comment ID: 24921 Letter Lines: 68 to 72 

Comment Code: 5700 2.12 Comments on the proposed duration of Class VI permits (seeking 

comment) 

Comment: 144.36: We believe it would be prudent to limit the life of the permit so that 

necessary adjustments to the permit can be made as needed with the opportunity 

for public comment and to establish a process for obtaining updated information 

concerning the injection operation. We would recommend a permit life of no more 

than 10 years. 

Individual Response: The final rule maintains the lifetime permit provision and clarifies that the 

permit extends through the post-injection site care period (144.36(a)). However, it also adds a 

requirement that the Director review each Class VI permit at least once every five years to 

determine whether it should be modified, revoked and reissued, terminated, or a minor 

modification made as provided in §§144.39, 144.40, or 144.41. The Director’s review will be 

informed by the owners’ or operators’ iterative reevaluation of the project. Specifically, the final 

rule includes a requirement that the AoR be reevaluated at least every five years, and also 

requires owners or operators to review and update the AoR and corrective action plan, the testing 

and monitoring plan, and the emergency and remedial response plan throughout the life of the 

project (146.84(e), 146.90(j), and 146.94(d)). Owners or operators must review each plan and 

identify necessary amendments or demonstrate to the Director that no amendment is needed. In 

no case can reviews occur less often than once every five years. The iterative process and 

subsequent plan reevaluations ensure that time and resources are committed to the most critical 

aspects of the permit in preventing endangerment to USDWs. 

EPA emphasizes that, in addition to the requirement that the Director review the permit every 

five years, as part of existing requirements at 40 CFR 144.39, the Director has the authority to 

revise the permit if project operations change or if the Director believes based on monitoring or 

operational data that the project may endanger USDWs. 

EPA has also added text to 144.39(a)(5) requiring permit modifications if the Director 

determines that a modification is necessary based on an AoR reevaluation, amendments to any of 

the project plans, or a review of the testing and monitoring results. The Director may also choose 

18
19

to require minor permit modifications under 40 CFR 144.41, depending on the extent of the plan 

amendment. All permit modifications, except minor modifications under 40 CFR 144.41, require 

an opportunity for public comment on the portion of the permit that is being reopened pursuant 

to requirements under 40 CFR Part 124. 

EPA believes that the iterative process of developing and executing the various plans required of 

GS well operators in the final rule (e.g., for AoR and corrective action, testing and monitoring, 

injection well plugging, post-injection site care, and emergency and remedial response) is 

tailored to the unique aspects of—and is more appropriate for–GS than establishing a finite 

permit duration (e.g., ten years as suggested by some commenters). 

The Agency plans to collect and review data on GS projects every six years 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.