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.1 Comments on Proposed Class VI UIC Rules

Docket ID No. EPA

- HQ

- OW

- 2008

- 0390

Robert J. Finley Illinois State Geological Survey University of Illinois

615 E. Peabod y Drive Champaign, IL 61820 finley @isgs.illinoi s.edu

The proposed Class VI regulations represent an important step in ensuring that USDWs are protected during geological carbon sequestration operations. Clearl y, very significant efforts have been made, and input has been received on man y i ssues to c raft the draft regulations. The comment process now underway offers an important opportunity to review the proposed regulations and address specifics that remain to be dealt with. With respect to suggested modifications, I find that the draft regulations are overly prescriptive on several points and not sufficiently performance based. With respect to some specific requirements, the objectives are not well defined such that required performance would

be difficult to determine. I would urge the U.S. EPA to take all comments received and

reissue a set of revised proposed regulations for further comment before finalizing Class

VI regulations

. My comments address specific points in the draft regulations, as outlined

below.

146.81

The discussion of pressure differential is of concern . A pressure differential of as little as 1 psi above the original reservoir pressure could theoreticall y allow fluids to move into a

USDW. I n reality , the capillary entry pressure of a reservoir seal may be such that it

preven ts fluid migration even if the buo yant forces of injected CO 2 exert pressure on the seal greater than pre

- injection hy drostatic pressure. Thus, this discussion must be modified to indicate that not only absolute pressure differences but capillary entry

pr essure of all seals must be considered.

146.82

Much of this section assumes that data are available from an injection well, such as the data referred to in (c) from log ging and testing of “the well.” The reality is that such a

well will not be drilled u ntil the permit is received

, so specific data, especially for a saline reservoir that has not been a hy drocarbon producer or gas storage unit elsewhere in its depositional basin, likely will not exist.

(d) (2 )

The entire discussion of faults is problemat ic here and elsewhere. Faults may be sealing,

as in the case of man y h ydrocarbon traps, or they may be transmissive, especiall y i n2

tensional stress regimes. I n compressive regimes, and if similar faults form hy drocarbon trap boundaries, faults are more l ikel y t o be sealing , but cannot be conclusively stated as

such from inferential data.

(d) (4 ) ( 5)

This section calls for data that is almost certainl y i ncompletely available and cannot be acquired except from a permitted well. Geomechanical information on the confining zone almost certainly will not exist until storage projects have been completed in a basin. There is no economic motive to develop such data. Acquiring a representative and accurate in situ fluid pressure in a confining zone may be impos sible given that a confining zone should not be permeable and therefore its testing with wireline or drillstem tools is highly questionable.

(g)

Reference is made to geochemical data on subsurface formations with no indication of

which formation or how many . This could be interpreted to mean all formations within the sedimentary column both above and below an injection zone at a given site. Much of

such data may be both irrelevant and unavailable and it will be extremely costly to core and sample ever y formation in the area of a proposed site

.

(i)(j)

These two sections appear to conflict in that (j) asks for the proposed formation testing program, which certainl y can be defined in advance of drilling the injection well, but preceding section (i) a sks for the results of compatibility testing based on the results of the proposed program. Also, what does compatibility mean? Modeling to date suggests that there may be both dissolution and precipitation of mineral phases as brine containing

dissolved CO 2 reacts with reservoir and confining layer rock. What is the standard for compatibility ? I f the apertures of microfractures are first enlarged but then carbonate or other minerals are expected to be reprecipitated, is that compatible? Much more

appro priate would be to ask for the expected pathway of geochemical and geochemical reactions with the standard being that the expected pathway s present no substantive risk of compromise to the sealing s ys tems.

146.83

(a)(2)

Modify this section to indicate t hat the confining zone is “reasonabl y ex pected’ to be free of faults and fractures that are transmissive. Again, the behavior of a given fault or

fracture in an area cannot be conclusivel y proven with respect to its impact on fluid flow except by analogy to oil field or gas storage field performance. There is no mechanism to

carr y out a subsurface test of a fault except possibly in the case of multiple wells opportunely place on opposite sides of a defined fault to access a transmissive unit which3

can be pressure pulse tested and can be isolated by packers or other equipment. Such

tests (obviously ) are unlikely to work in a confining zone due to its low permeability

.

(b)

The words “allow for pressure dissipation” are unclear in meaning with respect to

a dditional zones. I f there are no formations in the stratigraphic column at a sequestration

site which have been depleted below original reservoir pressure due to hy drocarbon production, all zones are likely to be at h ydrostatic pressure (or overpressured, as in parts

of the Gulf Coast B asin). Only in a few instances are formations encountered that have never been drilled and are at less than the basinal hydrostatic pressure gradient. This is the only case where leakage into such a unit may “allow for pre ssure dissipation”. Is that

what is meant here? I s uggest this phrase be carefully reviewed and considered for

deletion.

146.84

(c)

Who determines what corrective action is required in the area of review? If a Class II well has been plugged in confor mance with Class II requirements is that presumed to be adequate ? Different state agencies (in a primacy state) may be responsible for Class II and Class VI wells, potentially complicating oversight of corrective action.

(c)(1)

It is unclear to this r eviewer whether computational modeling can address the lateral and

vertical movem ent of all “formation fluids in the subsurface”. This needs to be restricted to the receiving reservoir. Further, it is unclear if current modeling can adequately

address bo th pressure driven fluid flow and density driven flow at plume boundaries that carries saturated brine away from free phase supercritical CO 2 at the plume margins.

Also, in a fully equilibrated column of reservoir rock at hy drostatic pressure, a 1 psi

dif ferential in a receiving reservoir could potentially be sufficient to cause fluids to migrate. However, the capillary entry pressure of the confining layer may prevent this.

As state d here, however, there is no accounting for cap illary entry pressure and its role in confining the injectate.

(c)(1)(iii)

What does this mean, “Consider potential migration”? Does this require modelin g faults as though they were tr ansmissive even though there may be no evidence of such?4

(d)

Use of corrosion resistant mat erials may not be possible in a number of situations so the “where appropriate” language can leave this provision open to significant argument and difference of opinion. Also, the extent of such materials is open to question. Is chrome steel adequate or is stainless steel required? What is the standard?

(c)(2)(vi)

This section (c) is headed tubing and packer and (2) requests information on requirements for such, but (vi) onl y r eques ts size of casing and leaves out size of tubing while (vii) ask for spe cifications on the tubing but likewise ignores basic size information.

146.87

(a)(1)

This section requires deviation checks for holes developed by drilling and reaming. An exception needs to be included, if this provision is to be kept, for drilling of core followed by reaming. Core is often collected with a bit OD resulti ng in a 4

- inch sample diameter;

however

, the hole being drilled may be larger than the core bit OD. Coring, usuall y i n 30

- foot or 60

- foot increments, may be followed by reaming befor e retu rning to use of the

full

- diameter drilling bit. There is no need to run a deviation check after this type of reaming , but such would be a violation of the regulations if this section were not modified to exclude coring operations.

(a)(2)

It is u nclear if it would be feasible to run all of these logs in surface casing . You have, perhaps, confused surface casing with intermediate casing. Surface casing often is only a few hundred feet in length and set to protect near

- surface USDWs . With fresh

- w ater mud in the hole and fresh water in the formations, the spontaneous potential log is useless and will not provide the readings you expect, such as you might get from a natural gamma ray tool as an alternative. Further, the diameter of the hole may be such that a caliper log cannot give accurate readings, since the drilled hole may be 20 or 24 inches. What is written would logically apply to intermediate casing, but there is no mention of

such.

(b)

This reads that the operator should submit the actua l whole or sidewall cores to the Director. Does the Director in every case have the staff and warehouse facilities to inventory , house, and curate these cores? I t seems to me that what should be required to

be submitted is any and all analy ses of the cor e material and that the cores themselves5

should either be retained by the operator for a period of time and/or the operator should (subsequentl y) submit the cores to a state geological survey or the U.S. G eological Survey core storage facility . The operat or could also contract with such a facility of house and curate the cores at the outset. Certainly, the actual cores should not be submitted to a regulatory authority with no provision for, or experience in, core curation.

(f)

These time requirements ar e not at all reasonable. Drilling and wellsite operations are b y their nature changeable depending upon conditions that arise during drilling and upon availability of oil field service equipment. No operator can predict such activities 30 day s in advance and likewise cannot predict schedule changes 30 day s in advance. No more than 10 day s notice shall be given for the advance schedule and changes must be allowable with 48 hours notice. Even 48 hours may not be doable in all situations for the

operator, but it would be a reasonable compromise between notice time and operational

considerations. If operators are required to report out

- of

- bounds conditions within 24 hours, regulators should be prepared to respond within a 10 day /48 hour framework.

146.88

(a)

Change first line to read: “Except during stimulation and fracture breakdown pressure testing....”

(c) The maintenance of an annulus pressure must be more carefully considered. Simply, a gauge on the annulus at the wellhead should not read a pressure above the injection pressure because there also exists the hy drostatic head of the annular fluid column in

addition to any applied pressure on the back side of the packer. The density of the fluid column must be considered and differences in density betw een that fluid and the fluid in the tubing must be considered. Those unfamiliar with this situation may consider the incremental gauge pressure as a requirement which could present a risk to the seating of the packer.

(e)

No downhole shut off s ystem sho uld be required. A complete s ys tem of surface shutoff valves at the wellhead, in the supply pipeline, at the compression station, etc. is much

more amenable to the intended safet y requirement than a downhole s ys tem. The operator should be required to dem onstrate adequate shutoff capacit y to the Director without mandate of a particular technology

.

Downhole shutoffs restrict the aperture of the injection tubing and tend to increase wellhead injection pressures. On most tubing

- run applications, they requir e hy draulic control lines to be run from where the valve is placed in the string through the tubing head to a surface platform. These devices complicate the completion by having a6

hy draulic line in the annulus and the internal diameter restriction may pre vent use of

certain tools run to evaluate the well or to remediate downhole conditions. Their use complicates an y operations to pull and replace tubing, packer, etc. There is no reason to

mandate one t ype of valve when pressure actuated wing safet y valve s can be used at the

surface. A safet y device can actuate the valve when falling below (or exceeding)

pressure parameters set in the actuator assembly . Downhole shutoffs are used in offshore applications where storms would preclude human intervention sho uld the wellbore and platform facilities be damaged or destro ye d. Their mandated use in all new Class VI

wells would exclude use of other s ys tems that may be fully adequate, more flexible, and allow more research data collection to take place on earl y wel ls.

146.89

(c)

The logs cited here are too prescriptive. A noise log is outdated technology that is highl y subjective in its interpretation. There is no mention of the need to run baseline logs. Certain logs have size restrictions. On an annual ba sis, only logs that can be run in tubing should be required, since implementing well control and pulling tubing annually is excessive and will cause wear at tubing connections and compromise the useful life of the tubing string. In fact, implementing this as an annual requirement seems excessive unless

another indication of an out

- of

- bounds condition is present.

146.90

(g)

Tracking of the pressure front needs to be further considered. What tools are suggested for tracking a pressure front in a saline r eservoir other than direct measurement at a wellbore? Should the primary seal over a saline reservoir be further penetrated by

wellbores just to obtain these data? What detection limits apply to the leading edge of a pressure gradient that are acceptable for monitoring? None of the indirect geophysical techniques listed are sensitive to in

- zone pressure changes in a single phase reservoir.

The monitoring option suggested in this section is a questionable option. If the confining

zone is maintaining th e desired integrit y, then monitoring in the first formation overly ing the confining zone should not show any pressure changes and hence will not inform as to the position of the pressure front or the CO 2 plume (via sampling)

. Onl y i f the confining

zone fa ils will this be viable

. Further, the “ first formation ” overl yi ng the confining zone

may not be suitable for any monitoring if it has little or no effective porosity and suitable permeability

. The implication is that y ou are proposing monitoring in a sui table (permeable) rock interval above the confining zone, but that may not be in the first stratigraphicall y defined formation.7

Are there stress or tilt sensors that be installed in a wellbore or at the surface that can indirectly detect a pressure front in the receiving reservoir? What is their resolution and how does that appl y i n a regulatory context? Surface tiltmeters are do not work in all situations, dependent on bedrock rigidit y and surface soil conditions/thickness.

Also, what is the definition of the CO 2 plume boundary ? I s it a given saturation over a given thickness? Is it any detectable amplitude brightening on a reflection seismic image or other geoph ys ical indication ?

146.93

(b)(1)

Monitoring for 50 years following cessation of injecti on has no particular basis in

research and should not be the rule against which an operator should be required to seek an exception as provided for in (b)(2). Rather, the regulations should require a maximum

post

- injection site monitoring plan for , for ex ample, 15 years to include comprehensive reservoir assessment, modeling, and simulation based on data collection during injection and then specificall y at closure, followed b y five years after closure, 10 years after closure, and 15 years after closure. T hese suggested intervals have a basis in the changes seen in the 4D seismic as Sleipner that show demonstrable geoph ys ical responses based on injection and plume development over about a 10 year period. Other groups have suggested 10 years of total post

- c losure monitoring, thus other repeat periods for site

survey s may be suggested and should be considered. For the example suggested here, t he

data taken at clos ure forms a baseline, such as plume extent based on a 3D seismic survey or other geoph ys ical tec hniques , and t hree subsequent survey s at five

- year intervals c ould

document plume migration and would serve to validate reservoir simulation. If the total

of four such example survey s (closure, +5, +10, and +15) and/or other appropriate monitoring techniq

ues, and the reservoir modeling and simulation, demonstrate a consistent and predictable understanding of subsurface behavior that does not endanger USDWs going forward, then the operator should be deemed to have fulfilled site closure responsibilities. T o repeat, there is no basis for the suggested 50 years of monitoring.

(b)(3)

What is the definition of a stable plume? I s it related to no detectable change with a given assessment technique; what technique(s) form the standard? If we were able to

do cument that a plume is shrinking, say in a confined geologic structure, due to dissolution into brine and decrease in the supercritical CO 2 phase, is that plume unstable?Letter ID: 0180 Commenter: Robert J. Finley Organization: Illinois Stat e Geological Survey

Letter ID: 0180 Comment ID: 23616 Letter Lines: 25 to 30

Comment Code: 1000 1. General and Administrative Comments

Comment: The proposed Class VI regulations represent an important step in ensuring that USDWs are protected during geological ca rbon sequestration ope rations. Clearly, very significant efforts have been ma de, and input has been received on many issues to craft the draft regulations. Th e comment process now underway offers an important opportunity to review th e proposed regulations and address specifics that remain to be dealt with. With respect to suggested modifications,

Individual Response: EPA acknowledges the comment. Pleas e see the remainder of EPA's responses to this comment for further deta ils. For additional information on EPA's final regulatory approach, please see the final rule and preamble as well as the rulemaking docket.

Letter ID: 0180 Comment ID: 23617 Letter Lines: 30 to 37

Comment Code: 1250 1.1.1.4 Flexibility is needed (p erformance-based standards)

Comment: specifics that remain to be dealt with. With respect to suggested modifications, I find that the draft regula tions are overly prescrip tive on several points and not sufficiently performance based. With re spect to some specific requirements, the objectives are not well defined such that required performance would be difficult to determine. I would urge the U. S. EPA to take all comments received and reissue a set of revised proposed re gulations for furthe r comment before finalizing Class VI regulati ons. My comments address specific points in the draft regulations, as outlined below.

Individual Response: The Agency believes that the Class VI requirements balance site-specific flexibility with USDW protection. Rather than setting performance or technology-based standards for GS projects, EPA is adopting a flex ible approach, where operators of GS projects would develop and implement site-specific plans for delineating the AoR, testing and monitoring the site, performing corrective actio n, and post-injection site care . EPA believes that the plans— which would be reviewed and approved by the Director and periodical ly updated throughout the life of the project—promote an ongoing dialogue between the operato r and the Director that will encourage use of the most appropriate t echnologies for a particular project.

Letter ID: 0180 Comment ID: 23618 Letter Lines: 39 to 48

Comment Code: 4110 2.4.1.1 Injection pressure limitations

1Comment: 146.81

The discussion of pressure differential is of concern. A pressure differential of as little as 1 psi above the original reservoir pressure could theoretically

allow fluids to move into a USDW. In r eality, the capillary en try pressure of a reservoir seal may be such that it preven ts fluid migration even if the buoyant forces of injected CO2 exert pressure on the seal greater than pre-injection hydrostatic pressure. Thus, this discussion must be modified to indicate that not only absolute pressure differences but capillary entry pressure of all seals

must be considered.

Individual Response: EPA believes that the 90 percent limit ation at §146.88(a) is an upper limit and provides a satisfactory margin of safety fo r all CO2 GS projects. EPA clarifies that the

Director will evaluate all site data, including information coll ected on reservoir pressures and capillary entry pressure, in setting the injection pressure for a GS permit. If the Director has reason to believe that a lower injection pressure limit is warranted, he or she can set the limit accordingly.

EPA clarifies that establishing a fracture pressure that will not exceed capil lary entry pressure of the injection zone ensures that the confining zone will not be fractured and will remain intact. In addition, capillary entry pressure measurements on core samples can quantify the amount of buoyant force the confining zone can maintain befo re failure (World Res ources Institute, 2008).

In addition, if there is any reason to believe that fracturing of the confin ing zone occurred during the injection process, potentially allowing fluid to move toward a USDW, the owner or operator

in consultation with the Director would have to stop injection, recalculate the injection pressure, reevaluate the AoR, and appropriately modify the injection pressure.

Letter ID: 0180 Comment ID: 23619 Letter Lines: 50 to 57

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82)

Comment: 146.82

Much of this section assumes that data are available from an injection well, such as the data referred to in (c) from logging and testing of "the well." The reality is that such a well will not be drilled until the permit is received, so specific data, especially for a saline re servoir that has not been a hydrocarbon producer or gas storage unit elsewhere in its depositional basin, likely will

not exist.

Individual Response: EPA agrees that not all of the information listed at §146.82 of the proposed regulation will be avai lable at the time the owner or operator develops their initial permit application. In response to comments and based on an evaluation of the proposed requirements at §146.82, the Agency revised this subpart so that the final regulation specifies

2separate requirements for information to be submitted with the permit application and before well construction is approved (at §146.82(a)) and in formation to be submitted before operation of the well is authorized (at §146.82(c)).

EPA believes that this revisi on of §146.82 addresses commenters' concerns regarding the timing of information to be submitted. In addition, section §146.82 in the final rule is similar to the permit application requirements for other inje ction well classes, which could help avoid confusion about how to meet the permitting requirem ents for Class VI wells. The requirements at §146.82(c) for information to be submitted before operation of the well is authorized are very similar to those for Class I wells, with modifi cations and additions th at address the unique challenges and types of data collected for GS wells.

EPA clarifies that operators would not necessarily need to core and sample each formation in the area of a proposed GS site. If relevant, compre hensive information abou t the site exists (e.g., from earlier geologic studies of th e area), the Director may, at his/ her discretion, allow its use in

the site characterization for th e GS project. In addition, §146.87( b) allows cores from nearby wells to be submitted if the owner or operator can demonstrate that core retrieval is not possible and that cores from nearby wells are representati ve of conditions at the GS well. EPA clarifies that, at a minimum, cores of injection zones and confining zones, and samples of formation fluids must be submitted. §146.87(b) gives the Di rector authority to require the owner or operator to core other formations in the bore hole if necessary to pr ovide sufficient geologic information to verify that the site is suitable for GS. EPA adds that §146.87(b) allows the owner or operator to submit whole cores or sidewall cores of the injec tion zone and confining system.

Letter ID: 0180 Comment ID: 23620 Letter Lines: 59 to 65

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82)

Comment: (d) (2)

The entire discussion of faults is problema tic here and elsewhere. Faults may be sealing, as in the case of many hydrocarbon tr aps, or they may be transmissive, especially in tensional stress regimes. In compressive regimes, and if similar faults form hydrocarbon trap boundaries, fa ults are more likely to be sealing, but cannot be conclusively stated as such from inferential data.

Individual Response: EPA believes that the requirement at §146.83(a)(2) that the confining

zone to be free of transmissive faults or fract ures is appropriate for Class VI wells and is necessary to ensure containment of the injectate and that requiring the co nfining zone to be free of transmissive faults maximizes protection of USDWs from endangerment. Class I hazardous waste injection well operators must also meet a similar requirement that the site is free of transmissive faults or fractures; they have su ccessfully made such demonstrations in the past. While core samples obtained through drilling and hydraulic testing are direct methods to obtain such information, geophysical techniques such as seismic or electromagnetic surveys can also be used in many geologic settings to demonstrate th e absence of or identify and characterize the

3presence of faults or fractures. At sites wher e deep faults (even with little or no surface expression) are present, pro cessing and interpreting data fr om multiple geophysical sensing

methods has been shown to detect faults better than an alysis of data from individual methods (Goussev et al, 2004). EPA adds that the Director must evaluate all geologic data on the site to ensure protection of USDWs from endangerment before approving a site for a GS project.

Letter ID: 0180 Comment ID: 23621 Letter Lines: 67 to 75

Comment Code: 3140 2.1.4 Comments that the proposed ge ologic data requirements are too stringent

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82)

Comment: (d) (4) (5)

This section calls for data that is almost certainly incompletely available and cannot be acquired except from a permitte d well. Geomechanical information on the confining zone almost certainly will not exist until storage projects have been completed in a basin. There is no economic motive to develop such data. Acquiring a representative and accurate in situ fluid pressure in a confining zone may be impossible given that a conf ining zone should not be permeable and therefore its testing with wireline or dr illstem tools is highly questionable.

Individual Response: EPA agrees that not all of the information listed at §146.82 of the proposed regulation will be avai lable at the time the owner or operator develops their initial permit application. In response to comments and based on an evaluation of the proposed requirements at §146.82, the Agency revised this subpart so that the final regulation specifies separate requirements for information to be submitted with the permit application and before well construction is approved (at §146.82(a)) and in formation to be submitted before operation of the well is authorized (at §146.82(c)).

EPA believes that this revisi on of §146.82 addresses commenters' concerns regarding the timing of information to be submitted. In addition, section §146.82 in the final rule is similar to the permit application requirements for other inje ction well classes, which could help avoid confusion about how to meet the permitting requirem ents for Class VI wells. The requirements at §146.82(c) for information to be submitted before operation of the well is authorized are very similar to those for Class I wells, with modifi cations and additions th at address the unique challenges and types of data collected for GS wells.

EPA adds that the presence or absence of an ec onomic motive for generating the data is outside the scope of the rulemaking. The owner or operator must submit all of the data required at §146.82 in order to support a determination about th e suitability of the si te, regardless of an economic incentive for gathering that data.

4Letter ID: 0180 Comment ID: 23622 Letter Lines: 77 to 84

Comment Code: 3140 2.1.4 Comments that the proposed ge ologic data requirements are too stringent

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82)

Comment: (g)

Reference is made to geochemical data on subsurface formations with no indication of which formation or how many. Th is could be interpreted to mean all formations within the sedimentary column both above and below an injection zone at a given site. Much of such data may be both irrelevant a nd unavailable and it will be extremely costly to core and sample every formation in the area of a proposed site.

Individual Response: The Agency believes that the re quirement at §146.82(a)(6) to submit baseline geochemical data on subsurface geologic formations, including all USDWs in the AoR is appropriate and protective of USDWs. EPA believes that this data will support monitoring plan development, inform injectate fate a nd transport model development (e.g., by providing appropriate input parameters), a nd provide information needed to respond to any unexpected and unpermitted leaks outside of the injection zone. Th e baseline geochemical information will allow the owner or operator and permitting authority to evaluate monitoring data and identify any changes in subsurface geochemistry that may indicate fluid movement.

EPA clarifies that the rule requi res geochemical analysis of, at a minimum, the injection zone, confining zone, and all USDWs ( §146.82(a)(6)). These geochemical te sts are necessary to ensure the adequacy of the confining system and to serve as a baseline for future monitoring. The

Director has the discretion to re quire geochemical analysis of a dditional subsurface zones if in the Director's opinion they are necessary for the protection of USDWs from endangerment.

EPA clarifies that operators would not necessarily need to core and sample each formation in the area of a proposed GS site. If relevant, compre hensive information abou t the site exists (e.g., from earlier geologic studies of th e area), the Director may, at his/ her discretion, allow its use in

the site characterization for th e GS project. In addition, §146.87( b) allows cores from nearby wells to be submitted if the owner or operator can demonstrate that core retrieval is not possible and that cores from nearby wells are representati ve of conditions at the GS well. EPA clarifies that, at a minimum, cores of injection zones and confining zones, and samples of formation fluids must be submitted. §146.87(b) gives the Di rector authority to require the owner or operator to core other formations in the bore hole if necessary to pr ovide sufficient geologic information to verify that the site is suitable for GS. EPA adds that §146.87(b) allows the owner or operator to submit whole cores or sidewall cores of the injec tion zone and confining system.

Additionally, EPA acknowledges co mments regarding the costs associated with thoroughly evaluating a potential GS site. The Agency beli eves the requirements for a thorough geologic site characterization for a GS proj ect are necessary to protect USDWs from endangerment.

5Letter ID: 0180 Comment ID: 23623 Letter Lines: 86 to 99

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82)

Comment: (i)(j)

These two sections appear to conflict in that (j) asks for the proposed formation testing program, which certainly can be defined in advance of drilling the injection well, but preceding section (i) asks for the results of compatibility testing based on the results of the proposed program. Also, what does compatibility mean? Modeling to da te suggests that there may be both dissolution and precipitation of mineral phases as brin e containing dissolved CO2 reacts with reservoir and confining la yer rock. What is the standard for compatibility? If the apertures of microf ractures are first enlarged but then carbonate or other minerals are expected to be reprecipita ted, is that compatible? Much more appropriate would be to ask for the exp ected pathway of geochemical and geochemical reactions with the standard being that the expected pathways present no substantive risk of compromise to the sealing systems.

Individual Response: EPA agrees that the formation testing plan must be approved before the owner or operator can generate necessary data on the compatibility of the CO2 stream with fluids in the injection zone and minerals in both the injection and the confini ng zone. In response to

comments and based on an evaluation of the proposed requirements, EPA revised subpart §146.82 so that the final regulati on specifies separate requirements for information to be submitted with the permit application and befo re well construction is approved (at §146.82(a)) and information to be submitted before opera tion of the well is authorized (at §146.82(c)).

Regarding compatibility, EPA clarifies that owners or operators must also present information on the compatibility of the CO2 stream with fluids in the injection zone and minerals in both the injection and the confining zone (s), as determined through the formation testing program and on the compatibility of the CO2 w ith the materials used to cons truct the well (§146.82(c)(3)). Based on this, the Director will determine the potential for geochemical reactions between the injectate (CO2) and the host geologic formations, which coul d result in the plugging of pore spaces or the

dissolution of formation minerals.

Letter ID: 0180 Comment ID: 23624 Letter Lines: 101 to 114

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83)

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

Comment: 146.83

(a)(2)

6Modify this section to indicate that the confining zone is "r easonably expected"

to be free of faults and fractures that are transmissive. Again, the behavior of a given fault or fracture in an area cannot be conclusively proven with respect to its impact on fluid flow except by anal ogy to oil field or gas storage field performance. There is no mechanism to car ry out a subsurface test of a fault except possibly in the case of multip le wells opportunely place on opposite

sides of a defined fault to access a tran smissive unit which can be pressure pulse tested and can be isolated by pack ers or other equipment. Such tests (obviously) are unlikely to work in a confining zone due to its low permeability.

Individual Response: The Agency believes that the re quirement at §146.83(a)(2) that the confining zone be free of transmissive faults or fractures is appropriate fo r Class VI wells and is necessary to ensure containment of the injectate and that requiring the co nfining zone to be free of transmissive faults maximizes protection of USDWs from endangerment. Class I hazardous waste injection well operators must also meet a similar requirement that the site is free of transmissive faults or fractures; they have su ccessfully made such demonstrations in the past. While core samples obtained through drilling and hydraulic testing are direct methods to obtain such information, geophysical techniques such as seismic or electromagnetic surveys can also be used in many geologic settings to demonstrate the absence of or identify and characterize the presence of faults or fractures. At sites wher e deep faults (even with little or no surface expression) are present, pro cessing and interpreting data fr om multiple geophysical sensing

methods has been shown to detect faults better than an alysis of data from individual methods (Goussev et al, 2004). Drilling through faults or fractures with a ppropriate well design, materials, and operation, would not result in an increase in their permeability or a decrease in CO2 containment properties of the related CO2 stor age reservoir. In some cases, the use of complementary drilling and geophysical met hods might provide the most dependable characterization of potential transmissive faults and fractures. EPA adds that the Director will evaluate all geologic data on the site to ensure protection of USDWs from endangerment before approving a site for a GS project.

EPA acknowledges that some smaller fractures may not be detectable during the site characterization process, and cl arifies that §146.82(a)(3 )(ii) requires the ow ner or operator to submit data on known or suspected faults and fractures (i.e., not al l fractures). Other requirements for GS injection wells and sites can mitigate the potential impacts of unidentified fractures. These include limitations on injec tion pressures to avoid propagation of existing fractures in the confining zone (§146.88(a)), co llection and assessments of CO2 monitoring data at the site, and AoR reevaluations (§146.84(e)) to assess possible CO2 movement through highpermeability regions (i.e., faults and/or fractures) not detected in the initia l site characterization.

Letter ID: 0180 Comment ID: 23625 Letter Lines: 116 to 127

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83)

7Comment: (b)

The words "allow for pressure dissipation" are unclear in meaning with respect

to additional zones. If there are no forma tions in the stratigraphic column at a sequestration site which have been deplet ed below original reservoir pressure due to hydrocarbon production, all zones are likely to be at hydrostatic pressure (or overpressured, as in parts of the Gulf Coast Basin). Only in a few

instances are formations encountered that have never been drilled and are at less than the basinal hydrostatic pressure gradient. This is the only case where leakage into such a unit may "allow for pr essure dissipation". Is that what is meant here? I suggest this phrase be car efully reviewed and considered for

deletion.

Individual Response: EPA clarifies that the primary purpose of the requirement for identification of additional confining zones wher e needed is to improve USDW protection in cases where a primary confining zone may not be sufficient to meet the UIC programmatic requirement to protect USDWs from endange rment. The Agency acknowledges that the additional confining formations may also, in site -specific circumstances, further impede vertical fluid movement, provide additional sites for m onitoring, mitigation, and remediation, and allow for pressure dissipation.

Letter ID: 0180 Comment ID: 23626 Letter Lines: 129 to 137

Comment Code: 3200 2.2 Proposed Area of Review and Corrective Action Requirements (40 CFR 146.84)

Comment Code: 3460 2.2.2.3 Acceptable corrective action techniques for GS sites (e.g., cements)

Comment: 146.84

(c)

Who determines what correc tive action is required in the area of review? If a Class II well has been plugged in conforma nce with Class II requirements is that presumed to be adequate? Di fferent state agencies (in a primacy state) may be responsible for Class II and Class VI we lls, potentially comp licating oversight

of corrective action.

Individual Response: The GS regulation does not specify th e corrective action methods to be

used on wells within the AoR to meet the re quirements of §146.84(d) and instead allows flexibility to ensure that all corrective action is appropriate to the well, the CO2 injection, and other site-specific conditions. All corrective action must be appropriate to the GS site to ensure

that the well does not allow CO2 or other fluids to move into or endanger USDWs and must be approved by the Director. EPA recognizes that wells plugged in accordance with Class II requirements may also be appropriately plugged for a CO2 GS project. EPA adds that all corrective action must be perf ormed pursuant to the approved AoR and corrective action plan,

8which affords the Director the discretion to requi re any additional information needed to ensure that all necessary correct ive action is performed.

EPA is developing guidance on AoR and corrective act ion at GS Class VI s ites to assist owners or operators and Directors in evaluating requi rements and proposed AoR and corrective action plans under §146.84. The guidance describes EPA's reco mmended approaches for the data to be

considered in an initial AoR delineation, how to apply computat ional modeling to delineate the AoR, performing corrective action at GS sites, and, when appropriate, completing AoR reevaluations. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

Letter ID: 0180 Comment ID: 23627 Letter Lines: 139 to 151

Comment Code: 3330 2.2.1.3 Applicability /adequacy of computational models (seeking comment)

Comment: (c)(1)

It is unclear to this reviewer whethe r computational modeling can address the

lateral and vertical movement of all "for mation fluids in the subsurface". This needs to be restricted to the receiving reservoir. Further, it is unclear if current modeling can adequately address both pressure driven fluid flow and density driven flow at plume boundaries th at carries saturated brine away from free phase supercritical CO2 at the plume margins. Also, in a fully equilibrated column of reservoir rock at hydrostatic pressure, a 1 psi differential in a receiving reservoir could poten tially be sufficient to cau se fluids to migrate. However, the capillary entry pressure of the confining layer may prevent this. As stated here, however, there is no acc ounting for capillary entry pressure and its role in confining the injectate.

Individual Response: EPA disagrees that modeling of only the receiving reservoir (i.e., the injection zone) is adequate in all cases to pr edict the potential movement of the CO2 plume and pressure front and ensure that USDWs will not be endangered. EPA believes, based on research and technical expert consultations , that available complex comput ational models can effectively simulate CO2 transport, fate, and changes in formation pressure in three dimensions. The Agency believes that these multiphase models will be able to incorporate factors such as pressure driven fluid flow, density driven flow, hydros tatic pressure and capil lary entry pressure.

Multiphase models have been used by States a nd industry for predicting the movement of water and solutes in soil, the behavior of non-aqueous phase liquid contaminants (e.g., trichloroethene) at hazardous waste sites, the re covery of oil and gas from petroleum-bearing formations, and more recently, CO2 in the subsurface.

9Letter ID: 0180 Comment ID: 23628 Letter Lines: 153 to 157

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling CO2 movement

Comment: (c)(1)(iii)

What does this mean, "Consider potential migration"? Does this require modeling faults as though they were transmissive even though there may be no evidence of

such?

Individual Response: EPA anticipates that the modeling w ould consider any potential fluid migration that may exist at the site . If site-specific geologic data indi cate that faults at the site are non-transmissive, then the model need not account for transmissive faults.

Letter ID: 0180 Comment ID: 23629 Letter Lines: 159 to 165

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

Comment: (d)

Use of corrosion resistant materials ma y not be possible in a number of

situations so the "where appropriate" language can leav e this provision open to significant argument and difference of opinion. Also, the extent of such materials is open to question. Is chrome steel adequate or is stainless steel required? What is the standard?

Individual Response: EPA clarifies that corrosion-resist ant materials and cement are not specifically required in a Class VI injection well. Rather, as stated in §146.86(b)(1), casings and

cement and other materials used must have suffici ent strength and be desi gned for the life of the sequestration project. Further, ma terials must meet standards listed in the rule and be compatible with fluids with which the materials may be expe cted to come into cont act. Therefore, some well materials may need to be acid-resistant and some may not if they do not come in contact with the

CO2 stream or other corrosive fluids and if approved by the Director.

The Director will evaluate the appropriateness of the proposed well construction based on sitespecific information about the injection project, including injection pressures, injection and confining zone lithology, and information a bout the carbon dioxide stream as provided in §146.86(b)(1). In addition to the flexibility given to the owner and operator, Director's discretion is specifically provided in §146.86(b)(1) for ca sing and cementing and §146.86(c)(2 and 3) for tubing and packer location and t ype. EPA is developing guidance on the construction of Class VI wells. This guidance will be av ailable on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

10Letter ID: 0180 Comment ID: 23630 Letter Lines: 167 to 172

Comment Code: 3820 2.3.1 Well construction procedures

Comment: (c)(2)(vi)

This section (c) is headed tubing and packer and (2) requests information on requirements for such, but (vi) only reque sts size of casing and leaves out size of tubing while (vii) ask for specificati ons on the tubing but likewise ignores

basic size information.

Individual Response: EPA has revised §146.86(c)(3 )(vi) to require the owner or operator to submit information on the size of both tubing and casing.. The Director will determine whether tubing size, as proposed by the owner or operator, is appropriate based on the size of the casing.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0180 Comment ID: 23631 Letter Lines: 174 to 186

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

Comment: 146.87

(a)(1)

This section requires deviation checks for holes developed by drilling and reaming. An exception needs to be included, if this provision is to be kept, for drilling of core followed by reaming. Core is often collected with a bit OD resulting in a 4-inch sample diameter; however, the hole being drilled may be larger than the core bit OD. Coring, usua lly in 30-foot or 60-foot increments, may be followed by reaming before returni ng to use of the full-diameter drilling

bit. There is no need to run a deviation check after this type of reaming, but such would be a violation of the regulati ons if this section were not modified to exclude coring operations.

Individual Response: EPA agrees that, in some cases, such as the situation mentioned by the commenter, a deviation check may not be nece ssary. EPA has modified the GS rule at §146.87(a)(8) to require the owner or operator to submit a pre-operatio nal testing plan that meets the requirements of §146.87. EPA adds that the Dire ctor would have discretion to approve a plan

without deviation checks that addresses circumstan ces where these tests may not be practical or useful, such as those mentioned by the commente r. EPA encourages owners or operators to

discuss these situations w ith the Director when pla nning the deviation testing.

11Letter ID: 0180 Comment ID: 23632 Letter Lines: 188 to 199

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

Comment: (a)(2)

It is unclear if it would be feasible to run all of thes e logs in surface casing. You have, perhaps, confused su rface casing with intermediate casing. Surface casing often is only a few hundred feet in length and set to protect

near-surface USDWs. With fresh-water mud in the hole and fresh water in the formations, the spontaneous potential log is useless and will not provide the readings you expect, such as you might get from a natural gamma ray tool as an alternative. Further, the di ameter of the hole may be such that a caliper log cannot give accurate readings, since the drilled hole may be 20 or 24 inches. What is written would logically apply to intermediate casing, but there is no

mention of such.

Individual Response: EPA disagrees that the listed surf ace casing logging requirements would provide inaccurate readings. Because the surfa ce casing runs through the lowermost USDW, it is imperative that the geology, lithology, and geochemistry of subsurface formations be defined and the integrity of the casing and cementing proven. EPA adds that th is type of testing has been successfully performed on Class I hazardous wells. EPA adds that intermediate casings are not required for all Class VI wells; however, if a well were to be constructed with an intermediate casing, the Director has authority to require appropriate loggi ng and testing, pe r §146.87(a)(5).

Letter ID: 0180 Comment ID: 23633 Letter Lines: 201 to 212

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

Comment: (b)

This reads that the operator should submit the actual whole or sidewall cores to

the Director. Does the Director in ev ery case have the staff and warehouse facilities to inventory, house, and curate these cores? It seems to me that what should be required to be submitted is any a nd all analyses of the core material

and that the cores themselves should e ither be retained by the operator for a period of time and/or the operator shoul d (subsequently) submit the cores to a state geological survey or the U.S. Geol ogical Survey core storage facility. The operator could also contract with such a facility of house and curate the cores at the outset. Certainly, the actual co res should not be submitted to a regulatory authority with no provision for, or experience in, core curation.

Individual Response: 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 mu st take whole cores or sidewall cores of the injection zone and confining system and formati on fluid samples from the injection zone(s), and

12must submit to the Director a detailed report pr epared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

Letter ID: 0180 Comment ID: 23634 Letter Lines: 214 to 226

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

Comment: (f)

These time requirements are not at al l reasonable. Drilling and wellsite operations are by their nature changeable depending upon conditions that arise during drilling and upon availability of oil field service equipment. No operator can predict such activities 30 days in advance and likewise cannot predict schedule changes 30 days in advance. No more than 10 days notice shall be given for the advance schedule and cha nges must be allowable with 48 hours notice. Even 48 hours may not be doable in all situations for the operator, but it would be a reasonable compromise between notice time and operational considerations. If operato rs are required to repor t out-of-bounds conditions within 24 hours, regulators should be prepared to respond within a 10 day/48

hour framework.

Individual Response: EPA disagrees that the 30-day notif ication requirement is unreasonable. The 30-day notification mirrors the current requ irement for logging and testing of new Class I wells, as described in §146.66. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide much needed field data for assurance of USDW protec tion from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ability to be

involved.

Letter ID: 0180 Comment ID: 23635 Letter Lines: 228 to 233

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4000 2.4 Proposed Injection Well Operat ing Requirements (40 CFR 146.88)

Comment: 146.88

(a)

Change first line to read: "Except duri ng stimulation and fracture breakdown pressure testing".

Individual Response: EPA clarifies that approved well stimulation is the only situation where owners and operators may exceed the 90 percent in jection pressure limitation. The final rule at §146.91(d)(2) also requires that the owner or op erator notify the Director 30 days before performing stimulation during inje ction operations; this will pr ovide an opportunity for the

13Director to review the owner or operator's plan s for stimulation and add other requirements as needed. EPA clarifies that UIC regulations prohibit fracturing of the confining zone at any time during injection or stimulation.

Letter ID: 0180 Comment ID: 23636 Letter Lines: 235 to 244

Comment Code: 4100 2.4.1 Injection parameters

Comment: (c)

The maintenance of an annulus pressure must be more carefully considered. Simply, a gauge on the annulus at the wellh ead should not read a pressure above the injection pressure becau se there also exists the hydrostatic head of the annular fluid column in addition to any a pplied pressure on the back side of the packer. The density of the fl uid column must be considered and differences in density between that fluid and the fluid in the tubing must be considered. Those unfamiliar with this situation may consider the incremental gauge pressure as a requirement which could present a risk to the seating of the packer.

Individual Response: EPA believes that maintaining an annulus pressure that is higher than the injection pressure, as required at §146.88(c), would ensure that if there are leaks in the tubing,

the annulus fluid would move into the tubing, rather than the in jectate moving out of the tubing and potentially along the length of the well. EPA adds that many characteristics of the annulus fluid and the injectate, including density as th e commenter suggests, must be considered in maintaining annulus pressure and that fluid dens ity should be considered when establishing an annulus pressure value at the surface.

Letter ID: 0180 Comment ID: 23637 Letter Lines: 246 to 269

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment)

Comment: (e)

No downhole shut off system should be re quired. A complete sy stem of surface shutoff valves at the wellhead, in th e supply pipeline, at the compression station, etc. is much more amenable to the intended safety requirement than a downhole system. The operator should be requ ired to demonstrate adequate shutoff capacity to the Director without ma ndate of a particular technology.

Downhole shutoffs restrict the aperture of the injection tubing and tend to increase wellhead injection pressures. On most tubing-run applications, they require hydraulic control lines to be run from where the valve is placed in the string through the tubing head to a su rface platform. These devices complicate the completion by having a hydraulic line in the annulus and the internal diameter restriction may prevent use of certain tools run to evaluate the well

14or to remediate downhole conditions. Thei r use complicates a ny operations to pull and replace tubing, packer, etc. There is no reason to mandate one type of valve when pressure actuated wing safety valves can be used at the surface. A safety device can actuate the valve when falling below (or exceeding) pressure parameters set in the actuator assembly. Downhole shutoffs are used in offshore applications where storms would preclude human intervention should the wellbore and platform facilities be damaged or de stroyed. Their mandated use in all new

Class VI wells would exclude use of othe r systems that may be fully adequate, more flexible, and allow more research data collection to take place on early

wells.

Individual Response: After evaluating the risks and benefi ts of down-hole shut-off systems and considering additional research, EPA will not re quire automatic down-hole shut-off devices for onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from endangerment. Instead, the final rule, at §146.88(e)(2 ), requires that owne rs or operators of

onshore Class VI wells install automatic surface shut-off devices. The rule affords Director's

discretion to mandate automatic down-hole shut -off devices in onshore situations that may warrant their use. The Agency agrees with the commenter that offshore Class VI wells present unique construction and operational conditions, including isolation fr om shorelines and the need to construct wells through the water column and the subsurface, which may delay response time in the event of well difficulties. The rule requires, at §146.88(e)(3), that owners or operators of

offshore wells within State territorial waters install automatic down-hole shut-off systems. EPA believes that these requirements at §146.88(e) ensure that proper precautions are taken to prevent subsurface fluid movement and ensure protection of USDWs.

EPA recognizes that down-hole shut-off devices may make well maintenance and operation more challenging. However, the bu oyant nature of CO2 and the elevated injection pressures

associated with GS increase the likelihood of an uncontrolled flow of CO 2 out of the well. If CO2 does begin to flow back up an injection we ll, it will rapidly cool and expand as it moves

toward the surface and can result in a stream of solid CO2 which can cause damage to the wellhead and other well instrumentation; such damage has been documented in CO2 ER wells (Skinner, 2003; Duncan et al ., 2008). Automatic shut-off devi ces can help prevent such occurrences, and EPA believes affording Director's discretion to require down-hole devices for onshore wells where necessary ensures that proper precautions are taken to prevent subsurface

fluid movement and ensure protection of USDWs.

EPA believes that requiring auto matic surface shut-off devices instead of down-hole devices for onshore wells provides more flexibility to ow ners or operators when performing required mechanical integrity tests. A dditionally, this requirement a ddresses concerns about risks associated with routine well workovers that may be complicated by the presence of down-hole devices while still maintaining USDW protection.

Letter ID: 0180 Comment ID: 23638 Letter Lines: 271 to 282

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

15Comment: 146.89

(c)

The logs cited here are too prescriptive. A noise log is outdated technology that is highly subjective in its interpre tation. There is no mention of the need to run baseline logs. Certain logs have size restrictions. On an annual basis, only logs that can be run in tubing should be require d, since implementing well control and pulling tubing annually is exces sive and will cause wear at tubing connections and compromise the useful life of the tubing string. In fact, implementing this as an annual require ment seems excessive unless another indication of an out-of-bounds condition is present.

Individual Response: EPA believes that the MITs describe d in the rule at §146.89 are effective methods and have been used successfully by injection well operators for decades and provide an important early warning of poten tial problems in the injection we ll system. EPA believes that the MITs described in §146.89(c) of the rule, including noise lo gs, are effective methods to demonstrate external MI to detect leakage along the wellbore, provide an important early warning of potential problems in the injection well system, and repres ent standard techniques that have been used successfully by the dri lling industry and the UIC program for many years. For additional information, please see the disc ussion of MITs in the final rule preamble.

EPA agrees with the commenter that flexibility to choose appropriate MITs is important, and the GS rule affords this flexibility by requiring th e owner or operator to prepare and gain approval for a project-specific testing and monito ring plan that incl udes MITs under §146.90. EPA clarifies that the regu lations allow the Director to requi re additional methods or, with the Administrator's approval, to approve the use of alternative MIT met hods based on specific information about the site or the well. See §146.89(e).

The final GS regulation retains the requirement that owners or operators of Class VI wells demonstrate injection well extern al mechanical integrity at le ast once annually at §146.89(c). EPA believes this is justifiable for the prot ection of USDWs from endangerment given the unique nature of CO2 GS relative to other injection operations, including the potential corrosive impact of CO2 in the presence of water and impurities on well materials, the potential geomechanical impacts to well integrity due to CO 2 phase changes, the temperature and pressure effects associated with injecti ng supercritical CO2, and the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA chose a more conservative initial approach in the early stages of deployment for GS.

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

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

16Letter ID: 0180 Comment ID: 23640 Letter Lines: 284 to 315

Comment Code: 4650 2.6.5 CO2 plume and pressure fr ont tracking (seeking comment)

Comment: 146.90

(g)

Tracking of the pressure front needs to be further considered. What tools are suggested for tracking a pressure front in a saline reservoir other than direct measurement at a wellbore? Should the pr imary seal over a sa line reservoir be further penetrated by wellbores just to obt ain these data? What detection limits apply to the leading edge of a pressu re gradient that are acceptable for monitoring? None of the indirect geophysical techniques listed are sensitive to in-zone pressure changes in a single phase reservoir.

The monitoring option suggested in this se ction is a questiona ble option. If the confining zone is maintaining the desired integrity, then monitoring in the first formation overlying the confining zone should not show any pressure changes and hence will not inform as to the position of the pressure front or the CO2 plume (via sampling). Only if th e confining zone fails will this be viable. Further, the "first formation" overlying the c onfining zone may not be suitable for any monitoring if it has l ittle or no effective porosity and suitable permeability. The implication is th at you are proposing monitoring in a suitable (permeable) rock interval above th e confining zone, but that may not be in the first stratigraphically defined formation.

Are there stress or tilt sensors that be installed in a wellbore or at the surface that can indirectly detect a pressu re front in the rece iving reservoir?

What is their resolution and how does th at apply in a regu latory context? Surface tiltmeters are do not work in all situations, dependent on bedrock rigidity and surface soil conditions/thickness.

Also, what is the definition of the CO 2 plume boundary? Is it a given saturation over a given thickness? Is it any dete ctable amplitude brightening on a reflection seismic image or ot her geophysical indication?

Individual Response: EPA has revised the pressure monitoring requirement for the final rule. EPA believes that direct pressure measurements are appropriate and th at direct pressure monitoring will be feasible at all GS sites. The final rule (at §146.90(g)) requires owners or operators to perform monitoring to track the extent of the CO 2 plume and pressure front. The owner or operator must use direct methods to m onitor for pressure change s in the injection zone. Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools) are also required unless the Director de termines, based on site-specific geology, that such methods are not appropriate.

17EPA believes that pressure monitoring in th e injection zone is n ecessary to track the development and movement of the pressure front and CO2 plume. Monitoring can also identify needed remedial actions, provide inputs for AoR reevaluation m odeling, evaluate predictions of plume movement, and target additional geoche mical and surface monitoring needs. Knowledge of the location of the CO2 plume and the associated pressure front will assure the public that GS projects are proceeding according to plan, provide sufficient information to the owner or operator and Director, or allow for appr opriate actions to address any indication that USDWs may be endangered.

EPA believes that geophysical (e.g., seismic) methods are useful for plume tracking at GS sites. Remote sensing methods and tiltmeters may also pr ove to be useful, but are not specified in the final regulation. Such methods may be an importa nt component of plume tracking at some GS sites. For this reason, the final rule at §146.90( g) requires the use of indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down-hol e CO2 detection tools) unless the Director determines, based on site-s pecific geology that such methods are not appropriate.

In response to comments regarding th e pressure front at GS sites, EPA clarifies that the pressure front (defined at §146.81) is the zone of elevated pressure that is created by the injection of CO2 into the subsurface. The pressure front of a CO2 pl ume refers to a zone where there is a pressure

differential sufficient to cause the movement of in jected fluids or formation fluids into a USDW. The pressure front includes all areas wherein pr essure is great enough to cause fluid movement

into a USDW if a conduit were to exist. The calcul ation of the threshold pr essure that defines the edge of the pressure front is dependent on pr operties of the injection and confining zones, including permeability, porosity, and compressibil ity, the distance between the injection zone and the lowermost USDW, and operational conditions including injection pressure and rate. For these reasons, the definition of the pressure fr ont is site- and project- specific, and a single pressure value can not be provided for all sites.

EPA is developing guidance on testing and mon itoring to assist owne rs or operators and Directors in evaluating requirements under §146.90, which will include discussion of identifying the extent of the CO2 plume and pressure front and the use of tiltmeters. The guidance describes available technologies and reco mmended approaches for implem enting a testing and monitoring plan, including pre-operational geophysical logging and testin g of injection wells, MITs, injection well testing during ope ration, groundwater quali ty monitoring, tracking the CO2 plume and pressure front, and soil gas and surface ai r monitoring which may be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequestration.cfm. In addition, in January 2009, DOE published a best practices manual entitled "Monitoring, Verificat ion, and Accounting of CO2 Stored in Deep Geologic Formations" (DOE/NETL-311/081508); this manual is included in

the docket for the for the final GS rule.

Letter ID: 0180 Comment ID: 23641 Letter Lines: 317 to 342

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

Comment Code: 5260 2.8.2.3 Adjusting the post-injecti on timeframe (seeking comment)

18Comment: 146.93

(b)(1)

Monitoring for 50 years following cessation of injection has no particular basis

in research and should not be the rule against which an operator should be required to seek an exception as provided for in (b)(2). Rather, the regulations should require a maximum post-injection site monitoring plan for, for example, 15 years to include comprehensive reser voir assessment, modeling, and simulation based on data collection during injection and then specifically at closure, followed by five years after closure, 10 y ears after closure, and 15 years after closure. These suggested inte rvals have a basis in the changes seen in the 4D seismic as Sleipner that show demonstr able geophysical responses based on injection and plume development over about a 10 year period. Other groups have suggested 10 years of total post-closure monitoring, thus other repeat periods for site surveys may be suggested and should be considered. For the example suggested here, the data taken at closure forms a baseline, such as plume extent based on a 3D seismic survey or othe r geophysical techniques, and three subsequent surveys at five-year interval s could document plume migration and

would serve to validate reservoir simulati on. If the total of f our such example surveys (closure, +5, +10, and +15) a nd/or other appropriate monitoring techniques, and the reservoir modeling a nd simulation, demonstrate a consistent and predictable understanding of subsurf ace behavior that does not endanger USDWs going forward, then the operator shoul d be deemed to have fulfilled site closure responsibilities. To repeat, th ere is no basis for the suggested 50 years of monitoring.

Individual Response: EPA disagrees that there is no basi s for the 50 year timeframe. In determining the post-injection s ite care-timeframe for the prop osed regulation, EPA reviewed industry reports, existing envir onmental programs, and initial GS research studies. EPA provided a synthesis of pertinent results from GS m odeling studies in the preamble to the proposed regulation. Further explanation of this analys is was included in an EPA-prepared background

document that is available in the federal docke t, titled "Computational Modeling of Underground Injection of Carbon Dioxide for Determinati on of Area-of-Review and Potential Risk to Underground Sources of Drinking Water." Based on review of these studies, modeling results indicate that the CO2 plume st abilization may occur on the time frame of 10-100 years after the cessation of injection. EPA believes that a 50-year default post-injection s ite care timeframe is a reasonable midpoint for most GS projects and available data, including data submitted by commenters, do not support a different default ti meframe, and has retained this in the final regulation.

However, EPA recognizes that there may be site s where the 50 year post injection site care timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. For this reason, the Class VI rule offers owners or operators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten

19or lengthen the PISC timeframe during the PISC period based on site-specific data, pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator to demonstrate, based on substantial data during the permitting process, that an alternative PISC timeframe may be appropria te if it ensures non- endangerment of USDWs pursuant to requirements at §146.93(c). EPA believes that a default post-injection site car e timeframe of 50 years, with flexibility to adjust the timeframe for a limited number of GS projects during the permitting process where

substantial data exists to demonstrate that an alternative timeframe would be protective of USDWs, or based on data collected during the PISC period, is appropriate to address the range of sites where GS is anticipated to occur, to ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-specific data, and be based on pressure monitoring and USDW impacts. EPA clarifies that, throughout th e post-injection site care timefra me, owners and operators must submit monitoring data results to the Director. At these times (or at 5 year intervals), the owner or operator may wish to discuss whether perf orming a non-endangerment demonstration may be appropriate. This scenario affords many of the suggestions the commenter offers.

Letter ID: 0180 Comment ID: 23642 Letter Lines: 344 to 350

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93)

Comment: (b)(3)

What is the definition of a stable plume? Is it related to no detectable change with a given assessment technique; what technique(s) form the standard? If we were able to document that a plume is shrinking, say in a confined geologic structure, due to dissolution into brine and decrease in the supercritical CO2 phase, is that plume unstable?

Individual Response: EPA acknowledges that many site-sp ecific factors will influence the determination of when the CO2 plume and pressu re front no longer pose a risk of endangerment

to USDWs. It is for this reason that EPA believe s that individual UIC Dir ectors, 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 grad ients 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.

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the guidance will assist Directors in evaluating propo sed well plugging plans a nd post-injection site

2021 care and site closure plans under §146.92 a nd §146.93. The guidance describes recommended approaches for how an owner or operator coul d plug injection and m onitoring wells; perform post-injection monitoring; dem onstrate non endangerment; and perf orm site closure activities. The guidance will be available at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.