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

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- 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 G E OLOGIC 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 b y t he Environmental Pro tection Agency :

1. T he potential negative impact to large CO2 deep saline formation geologic sequestration projects resulting from the reference in these regulations to storage rather than disposal, imply ing the CO2 may have value or is even actually a com modity . Large projects could have a CO2 plume covering man y s quare 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 w ork 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 seq uestered in geologic formations. Additional research is needed to evaluate and determine this impact. This includes obtaining a much better understanding of the geochemistr y i nvolved, plume movement, plume tracking methods and plume fate.

4. The establishm ent of the precedence of developing a new well class when a unique or unusual well ty

pe is encountered . We believe the existing well classification framework can address this well ty

pe, thus simplify ing administration of this ty pe of well.

5. Consider devel oping regulations that actually address an injection/withdrawal ty pe project much similar to a natural gas porosit y s torage s ys tem. In this scenario the CO2 is contained in a limited, defined geologic trap and the sy stem is designed to inject the CO2

or wi thdraw the CO2 as needed.

6. The practicality and appropriate ness of liability stay ing with the owner/operator for an extended period o f time. Should instead, some form of a Federal/I ndustry partnership be implemented to address this issue, especiall y s ince this technology is be ing pushed at a

national level as a significant method for reduc ing CO2 releases to the atmosphere?BUREAU OF WATER

– GEOLOGY SECTION

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KDHE Comments EPA CO2 Regulations September 16 , 2008

Potential costs and legal issues in rega rds to long term liability could limit the number of projects implemented.

7. Adequate funding must be provided b y EPA to the states so the states can properl y administer these wells in a protective manner. This is new, additional w ork for the states that EPA is responsible for funding. Current funding provided b y EPA does not adequatel y cover the costs of existing state UI C programs, let alone this additional work.

Comments on Specific Regulation s :

144.1, 146.6,

144.15 : Sa me 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 c on cerning the injection operation. We would recommend a per

mit 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 man y s quare miles. We suggest using

the criteria for the AoR as found in exist ing 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 wi ll 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

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KDHE Comments EPA CO2 Regulations September 16 , 2008

146.82 (g) : Needs to li st 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 ini tiating 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): T he CO2 plume will never cease moving. Even deep formations have a

natural flow gradient. There will also likel y 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

financ ial condition can change quickl y. With the financial test there may

be nothing tangible available to cover the costs of plugging, clos ure 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 multilay er protection s ys tem provided b y t he requirement of tubing and packer and the longstring being c emented

bottom to surface. S etting 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 dee pest water bearing zone that is currently used for a water supply

.

146.86 (b)(3): KDHE strongl y s upports 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 lay er of protection of the public health, safet y and environment.BUREAU OF WATER

– GEOLOGY SECTION

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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 ty pe of formations encountered.

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

actuall y be supe rior to the cement bond log in many situations. The cement evaluation log provides a 360

- degree map of the cement and can

actuall y s how the orientation and extent of channeling.

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

may actuall y be superior to the cement bond log in many situations. Also, should require an initial casing inspection log to establish baseline casing

conditions

, especiall y s ince corrosion is a c oncern in this ty pe of well and then conduct p eriodic 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 beca

use 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 Dire ctor. 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

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KDHE Comments EPA CO2 Regulations September 16, 2008

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

geo logy , hy drogeology 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 safet y factor. The 0.90 gradient is too high in our opinion and

does not allow much of a safet y 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)

sy stem be used. This sy stem also allows for monitoring and data trending to detect anomalies or potential problems before they occur. The s ys tem can also be programmed to automatically shut

- in valves and to alarm based on certain parameter values. This s ys tem 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 su rface

.

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

using an approved liquid. This MI T s hould stress the sy stem and be at a pressure above the normal operating pressure so that potential problems

are identified b y t h e 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 corros ion problems and the degree of corrosion casing inspection logs conducted periodicall y i s a good method for monitoring corrosion in the well. Annual testing is excessive in our opinion. Could require this annuall y fo r say for the first three years and then go to once

every five year interval if approved b y t he Director. How would the temperature log work or be implemented for this test? I s 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 anomal y? Or, is the concept that the well is shut

- in for a time period and then a

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

of shut

- in temperature logs conducted and a composite of the sh ut

- in logs is then analy zed to track upwards migration of CO2?BUREAU OF WATER

– GEOLOGY SECTION

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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

- gravit y t he difference in values or readings would most likely be so small that these would pr obably be less than the measurement error of the equipment. There has to be a significant difference in densit y t o 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 b y t he regulatory

agency to ensure problems are identified and addressed in a ti mel y manner. Think about this for example

- quarterl y reporting for say the

third calenda r quarter results in data that is collect ed July 1, 2008, would

not be seen b y t he regulatory agency before October 30, 2009, if the operator is allowed say 30 day s after the end of the quarter to provide the report. Is tha t reasonable or appropriate ?

The timeframe for submittal of the q uarterl y report should be stated

.

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

hole pressure should be determined p rior 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 densit y 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 wa rrant additional review by the Environmental Protection Agency:

1. The potential negative impact to larg e CO2 deep saline formation geologic sequestration projects resulting from th e reference in these regulations to storage rather than dispos al, 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, wh ich may involve dealing with numerous parties, considerable legal wo rk and considerable costs.

2. The potential adverse impact to Class I industrial waste disposal well program that could result from the con cept 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 im portant issues that need to be addressed; however, these are generally addressed thou gh 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 regul atory 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 u nderstood about the behavior of CO2 sequestered in geologic formations. Additi onal research is needed to evaluate and determine this impact. This incl udes obtaining a much better understanding of the geochemistry involved, plume move ment, plume tracking methods and plume

1fate.

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 re lated to GS, including projects that address many of the topics suggested by commenters. EPA pub lished 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 tw o studies by the Lawrence Berkeley National Laboratory on the potential effect s of CO2 injection on ground wa ter 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 re gulating GS under the UIC Program. Even after finalization of the GS regulation, the Agency plan s to collect and review data every six years on GS projects to determine whether the appropr iate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are approp riate 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 encoun tered. 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 we ll 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 specifi cally to address the risks posed by long-term storage of CO2 (i.e., very large volumes, very long time-per iods, 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

2Comment: 5. Consider developing regulati ons 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 limite d, 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 addr esses injection wells designed for longterm sequestration of carbon dioxide; the Class VI designation and permit requirements are not applicable to owners or operators th at plan to withdr aw 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 enda nger USDWs, and theref ore has developed new Class VI regulations to address these risks. Furt hermore, the GS requireme nts 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 EP A 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 cove r 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 acquiri ng 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 th at 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 ar e 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 lia bility 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 implemente d to address this issue, especially since this technology is being pushed at a national level as a significant

3method for reducing CO2 releas es to the atmosphere?

Potential costs and legal issues in rega rds to long term liability could limit the number of projects implemented.

Individual Response: Under the final GS rule, once an owne r 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 opera tor will generally no longer be subject to enforcement for regulatory noncompliance. Furtherm ore, their financial instrument as required under §146.85 will be released if it was not used. However, even if a site closure is approved under §146.93, an owner or operator may be held liable for regulatory noncompliance (including violation of 40 CFR 144.12) in ce rtain circumstances. For example, an owner or operator may be held liable for regulatory noncompliance even afte r site closure was approved if the Director relied on erroneous information (e.g., erroneous modeling data) provid ed by the owner or operator when approving site closure.

Separate from EPA’s authority to enforce regul atory compliance, an owner or operator may be subject to a §1431 response orde r even after proper site cl osure is approved under §146.93. Under §1431 the Administrator may require an ow ner or operator to take necessary response

measures if he or she receives information that a contaminant is present or is likely to enter a public water system or an USDW, which may pres ent an imminent and s ubstantial endangerment to the health of persons, and the appropriate Stat e and local authorities ha ve not acted to protect the health of such persons. Th e action may include issuing admi nistrative orders or commencing a civil action for appropriate relief against the ow ner or operator of a Class VI well. If the owner or operator fails to comply with the order, they may be subject to a civil penalty for each day in

which such violation occurs or failure to comply continues.

Furthermore, after site closure an owner or ope rator may remain liable under tort and other remedies, or under other federal statutes includi ng, but not limited to, Clean Air Act, 42 U.S.C. §§ 7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. Please note that EPA does not have authority to transfer SDWA or other legal liability for Class VI wells to the State or federal gove rnment 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 genera l authority to set fi nancial responsibility requirements for injection well owners or operato rs to ensure that adequate resources are available to protect USDWs thr oughout the life of the GS project. However, this authority does not extend to allowing the Agency to create a fi nancial 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 th at are addressed as financial re sponsibility instruments through the GS rule are set up by individual ow ners or operators and are differe nt 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/ed its to rule language

4Comment 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 obt ain a permit prior to construction.

Individual Response: EPA clarifies that any owner or operato r seeking to construct an injection well must obtain a permit before beginning injecti on, but not necessarily the construction of the well. Owners and operators of Class VI we lls for long-term sequestration or Class V experimental technology wells (for experimental GS projects) mu st submit information about the well, the geology of the site, and the planned injection to demonstr ate 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 CO 2; purity standards for CO2

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

concentration of CO2 should be established to ensure th at it is actually a CO2 sequestration project and to limit the injection of othe r 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 addresse s 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 propertie s. Specifically, the GS rule requi res the owner or operator to submit data about the site, including an analysis of the chemical and physi cal characteristics of the CO2 stream, as required at §146.82(a)(7)(iv), and informati on on the compatibility of the CO2 stream with fluids in the injection zone a nd minerals in both the in jection 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 geoche mical 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 inj ection 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 Cla ss 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/M odeling 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.

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

For Geologic Sequestration Project defi nition, 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 e ndangered by the injecti on activity. The area of review is delineated using computational mode ling that accounts for the physical and chemical properties of all phases of the injected CO2 stream and is based on available site characterization, monitori ng, 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 fr ont 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 s hould 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 USDW s, 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), re quires the owner or operator to submit baseline geochemical data on subsurface geologic formations. EPA is not specifying for

which formations this information should be su bmitted 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 pot entially 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 a dditional 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 regard ing characterizing the region al geology and hydrogeology of a

6proposed GS site as well as performing th e necessary geochemical, geomechanical, and geophysical analyses of the injection and conf ining zone. The guidance can be found on EPA’s website at http://water.epa.gov/type/gr oundwater/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 initia ting or propagating fractures in the injection in addition to the confining zone.

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

zones that are free of transmissive faults and fract ures but disagrees that the rule should prohibit fracturing within the injection zone. EPA believe s that, in some circumstances, fracturing is necessary (i.e., in association with an appr oved stimulation program) to improve wellbore and formation injectivity. EPA clarifies that all stimul ation for GS must be reported to the Director for approval 30 days in advance of such activit ies, pursuant to require ments 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 ev aluating 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 re tains the requirement at §146.83(b) which affords the Director discretion to require owners or op erators 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/M odeling 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 gradie nt, diffusion, and density gradients; however,

7EPA believes that plume movement may stabilize at a point where movement of the CO2 plume slows or pressures in the injec tion 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 inject ion. As discussed in the preamble to the proposed GS regulation and the associated background document, "Computat ional 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 sp ecify a timeframe over which the AoR delineation model should run. Rather, the model should be us ed to predict the ultimate plume movement up to the point the plume movement ceases or pressure s 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 financia l responsibility requirements (40 CFR 146.85)

Comment: 146.85: Specifics need to be listed for providing acceptable financial responsibility. We recommend that the fina ncial 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 responsib ility instruments at §146.85(a)(1). EPA has clarified the fina ncial responsibility requirements by: 1) Describing “qualifying instruments” to c over the cost of correc tive action, injection well plugging, PISC and site closure, and emergency and remedial res ponse in a manner that prevents endangerment of USDWs. 2) Adding language clarifying that the financial re sponsibility 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 us e of a financial test is not appr opriate to ensure that resources will be available over the long term , the Director will have the di scretion to not allow financial tests as a financial responsibility instrument for PISC and closure.

EPA is developing guidance that will provide mo re 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

8demonstrations.

EPA is retaining the financial te st as an option to demonstrate financial responsibility for Class VI wells. EPA believes that, if pr operly 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 thos e mentioned by the commenter, EPA is developing guidance (available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequest ration.cfm) to assist Directors in evaluating the appropriateness of the financ ial 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 th e requirement of tubing and packer and the longstring bei ng 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 allo w 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 cemente d 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 USDW s are protected. See the

discussion of Class VI well constr uction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is de veloping guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

EPA disagrees that other requirements for Cla ss 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 US DW protection. EPA belie ves 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)

9Comment: 146.86 (b)(3): KDHE strongly supports the re quirement 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 protecti on of the public health, safety and environment.

Individual Response: EPA acknowledges the comment and ag rees 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, betwee n formations, and above the injection zone and will ensure competency of Class VI wells and protect US DWs 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 requir ements 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 cas ing is used and is cheap insurance. Also gives a good baseline to start with.

Individual Response: Although the rule does no t 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 opera tors to submit information on planned injection pressures, which the Director will use in ev aluating the proposed cas ing, tubing, and packer design. EPA adds that, in determining the suitabil ity of well materials and the design of the well,

the Director must consider vari ous aspects of the injection proj ect, including injection pressure, external pressure, inte rnal pressure and axia l loading in §146.86(b)(1)(i i), 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 th e type of formations encountered.

146.87 (a)(2)(ii): Should also allow the opti on 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.

10146.87 (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 in spection log to establish baseline casing conditions, especially since corrosi on is a concern in this type of well and then conduct periodic casing inspecti on 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 conduc ting the log to esta blish 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 expe rience, gas is not a sensitive test medium due to its significant compressibi lity. A liquid provides an extremely sensitive test because of its incompre ssibility 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 Dire ctor 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 stor age of the core for review and consideration of approval by the Director. A core repor t, including the test results and the geomechanical characterist ics and values determined such as fracture gradient shall be submitted to the Director. The requirement for the

core itself could be that the core shal l be made available for inspection by the Director upon the reques t 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 th an resistivity and spontaneous potential logging. Gamma logs can provide information on the mineral composition of the formations, but do not provide the physical (lithologic a nd stratigraphic) information av ailable from resistivity and spontaneous potential logs. Gamm a logs also do not provide info rmation 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 cl arifies 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 disa grees 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 character istics would be known and could be compensated for by calculation. EPA clarifies thatpressure testing of the inject ion 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 injec tion is required at §§146.88(e) and 146.89(b).

11Regarding 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 confin ing 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 (inc luding well logs), core analys es, 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 i ndustry practice and research to identify cementing flaws. EPA adds that these tests are necessary to verify in formation about the injection and confining zones,

and ensure that the well is bei ng drilled and cased as approved a nd has mechanical integrity. This information demonstrates that the well can be opera ted and tested in a manner that will meet the requirements for Class VI wells. Should alternativ e methods be shown to provide equivalent or better information, the Director may allo w 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 pressu re/gradient should be de termined based on the site geology, hydrogeology and geomechanics. KDHE’s "rule of thumb" is that injection pressure not exceed a gradie nt 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 s uggestion 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 Di rector has the author ity, 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 injec tion zone. During injection, the pressure in the injection zone must not exceed 90 percent of th e 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 geomech anical 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 frac ture pressure. Examples include the step-rate test, in-situ stress tests, and a combination of a long spaced soni c log with laboratory measurement of the mechanical properties of cores.

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

12Comment Code: 4100 2.4.1 Injection parameters

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

word fluid should not be used. A flui d 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 practi ces, 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 C ontrol and Data Acquisition (SCADA) system be used. This system also allo ws for monitoring and data trending to detect anomalies or potential problems before they occur. The system can also be programmed to automatically shut-in va lves 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 beli eve it is necessary to specify what type of equipment is to be used to trigger the shut-off system. Instead, the regula tion allows the owner or operator some flexibility in deciding what equipm ent 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 li nked 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 mechani cal integrity monitoring (seeking comment)

Comment: 146.89 (b): Should include also the requireme nt for an annual annulus pressure MIT using an approved liquid. This MIT s hould stress the system and be at a pressure above the normal operating pre ssure so that potential problems are identified by the test, thus the proble m 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

13of GS injection wells, instead of periodic testing, which is required for most other types of deep injection wells, is necessary give n the potential corrosive impact of CO2 in the presence of water and impurities on well materials, the potential ge omechanical impacts to well integrity due to CO2 phase changes, and the temperature and pr essure effects associated with injecting supercritical CO2. The regulati on, at §146.89(e), provides the Direct or 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 (C IL) 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 degr ee of corrosion casing inspection logs conducted periodically is a good method fo r 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-st ring casing, and is required if the Director determines that it is necessary based on site-s pecific information. EPA has revised the final GS rule to require that the frequency of the casing in spection 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 opini on. 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 te mperature log work or be implemented

Individual Response: EPA disagrees that the annual mechani cal integrity testing is excessive. EPA retains the requirement that owners or ope rators of Class VI wells must demonstrate injection well external mech anical integrity at least once annually under §146.89(c). EPA believes this is justifiable for the protecti on of USDWs from endangerment given the unique nature of CO2 GS relative to other injection operations, including the pote ntial 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 ch anges, the temperature and pressure effects associated with injecting supercritical CO2, and the buoyant nature of th e injected CO2. Because of the unknown long-term effects of CO2 GS, EPA chose a more cons ervative initial approach in the early stages of deployment for GS.

14EPA is using an adaptive approach to regulati ng GS. The Agency plans to collect and review data every six years on GS projects, including MI T data, to determine whether the appropriate amount and types of information and appropria te documentation are being collected, and to determine if modifications to the requ irements 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 te mperature log work or be implemented for this test? Is this based on the concep t that should the CO2 migrate upwards behind the casing that it will de-pre ssure and flash to a gas causing a measurable temperature anomaly? Or, is th e 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 temperatur e 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 describe d in §146.89(c) of the rule (e.g., an approved tracer log or temperat ure or noise logs) are effec tive 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 Direct or 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 warni ng of potential problems in the injection well system. EPA is developing guidance on monitoring and testing to assist owners/operators and Directors in evaluating requi rements under 146.90, including pr oposed 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/groundwat er/uic/wells_se questration.cfm.

EPA is using an adaptive approach to regulati ng GS. The Agency plans to collect and review data every six years on GS projects to determ ine whether the appropria te 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 a ny 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

15that these would probably be less than th e 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 re garding the use of geophysical t echniques at some sites because the Agency recognizes that geophysical methods ar e not appropriate in al l geologic settings. For example, geophysical methods are difficult to ex ecute in areas that are structurally and topographically complex or where lithologies have limited contrast in density, porosity, permeability, and other physical properties. EPA clarifies that this determination will be made by the Director based on the site-specific geologi c information submitted by the owner or operator with the permit application.

EPA believes that this approach provides flexibility to develop a site-specific monitoring plan and recognizes that indirect techniques are no t appropriate in all s ituations. The owner or operator's approved testing and monitoring pl an will include the site-specific details, technologies, testing and monitoring freque ncies, 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 re porting. This is information that is important and needs to be reviewed at a frequency by the regulatory agency to ensure problems are identified and addr essed in a timely manner. Think about this for example - quarterly reporting for say the third calendar quarter

results in data that is collected Ju ly 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 qua rter to provide the report. Is that reasonable or appropriate?

The timeframe for submittal of the qu arterly report s hould be stated.

Individual Response: The final rule remains unchanged from the proposal and requires semiannual reporting of monthly aver age, maximum, and minimum va lues 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 addi tional information, please see the final rule and the preamble for a discussion of EPA's fina l approach to recordkeeping and reporting.

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

Comment Code: 5100 2.8.1 Injection well plugging activ ities (seeking comment) (40 CFR 146.92)

Comment: 146.92 (a): We believe the sequence of wo rk 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 determin e bottomhole reservoir pressure. In addition, the injection well plugging plan must include anappropriate 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 be come 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 plum e will never be completely stabile. The CO2 plume will continue to move by a combination of methods including density differences, natural formation flow gr adients and diffusion. Recommend dropping the reference to the plume or pressure front having stabilized.

Individual Response: EPA clarifies that in the final ru le, §146.93(b)(3) no longer requires the plume and pressure front to have stabilized. EP A 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 potentia lly impacted parties.

EPA agrees that a complete cessa tion of plume movement may not occur at some sites for long time periods due to density differences, natura l formation flow gradie nts, and diffusion. EPA clarifies that a complete cessati on of plume movement is not requi red, only a demonstration that the plume and pressure front no longer pos e 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 closur e and post-injection site care

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

17Comment: 146.93 (f): This will be impractical for la rge sequestration projects due to the paperwork and legal work to deal w ith a significant number of parties.

Individual Response: EPA disagrees that the owner or opera tor 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 a ppropriate for the post-injection and site closure period to ensure that data are availabl e 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 durati on 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 pr ocess for obtaining updated information concerning the injection operation. We woul d 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 car e 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, re voked and reissued, te rminated, 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 operato rs’ iterative reev aluation of the project. Specifically, the final rule includes a requirement that the AoR be reev aluated 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 reme dial response plan th roughout 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 ev ery 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 preven ting endangerment to USDWs.

EPA emphasizes that, in addition to the requirement that the Di rector 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 pr oject may endanger USDWs.

EPA has also added text to 144.39(a)(5) requiri ng permit modifications if the Director determines that a modification is necessary base d on an AoR reevaluation, amendments to any of the project plans, or a review of the testing and monitoring resu lts. The Director may also choose

1819 to require minor permit modifications under 40 CFR 144.41, depending on the extent of the plan amendment. All permit modifications, except mi nor 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 develo ping and executing the va rious plans required of GS well operators in the final rule (e.g., for AoR and corrective action, testing and monitoring, injection well plugging, pos t-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 appr opriate or necessary.