This comment letter response contains two parts:   

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(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.  

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base. As a result, there may be some typographical errors attributable to optical

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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. Peabody Drive

Champaign, IL 61820

finley@isgs.illinois.edu

The proposed Class VI regulations represent an important step in ensuring that USDWs 

are protected during geological carbon sequestration operations. Clearly, very significant 

efforts have been made, and input has been received on many issues to craft 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 theoretically allow fluids to move into a 

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

prevents 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.

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 

reservoir that has not been a hydrocarbon producer or gas storage unit elsewhere in its 

depositional basin, likely will not exist.

(d) (2)

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

as in the case of many hydrocarbon traps, or they may be transmissive, especially in 
2

tensional stress regimes. In compressive regimes, and if similar faults form hydrocarbon 

trap boundaries, faults are more likely to be sealing, but cannot be conclusively stated as 

such from inferential data.

(d) (4) (5)

This section calls for data that is almost certainly incompletely 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 impossible 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 every 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 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 date suggests 

that there may be both dissolution and precipitation of mineral phases as brine containing 

dissolved CO2 reacts with reservoir and confining layer rock. What is the standard for 

compatibility? If the apertures of microfractures are first enlarged but then carbonate or 

other minerals are expected to be reprecipitated, is that compatible? Much more 

appropriate would be to ask for the expected pathway of geochemical and geochemical 

reactions with the standard being that the expected pathways present no substantive risk 

of compromise to the sealing systems.

146.83

(a)(2)

Modify this section to indicate that the confining zone is “reasonably 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 analogy to oil field or gas storage field performance. There is no mechanism to 

carry 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 which 
3

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 

additional zones. If there are no formations in the stratigraphic column at a sequestration 

site which have been depleted 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 pressure dissipation”. Is that 

what is meant here? I suggest 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 conformance 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 reviewer whether computational modeling can address the lateral and 

vertical movement 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 both pressure driven fluid flow and density driven flow at plume boundaries that 

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 potentially be sufficient to cause fluids to 

migrate. However, the capillary entry pressure of the confining layer may prevent this. 

As stated here, however, there is no accounting for capillary entry pressure and its role in 

confining the injectate.

(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?
4

(d)

Use of corrosion resistant materials 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) only requests size of casing and leaves out size of tubing while (vii) ask 

for specifications 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 resulting in a 4-inch sample diameter; 

however, the hole being drilled may be larger than the core bit OD. Coring, usually in 

30-foot or 60-foot increments, may be followed by reaming before returning 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 unclear 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-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 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 actual 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? It seems to me that what should be required to 

be submitted is any and all analyses of the core material and that the cores themselves 
5

should either be retained by the operator for a period of time and/or the operator should 

(subsequently) submit the cores to a state geological survey or the U.S. Geological 

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 cores should not be 

submitted to a regulatory authority with no provision for, or experience in, core curation.

(f)

These time requirements are not at all 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 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 hydrostatic 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 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.

(e)

No downhole shut off system should be required. A complete system of surface shutoff 

valves at the wellhead, in the supply pipeline, at the compression station, etc. is much 

more amenable to the intended safety requirement than a downhole system. The operator 

should be required to demonstrate adequate shutoff capacity 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 require hydraulic 

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 a 
6

hydraulic line in the annulus and the internal diameter restriction may prevent use of 

certain tools run to evaluate the well or to remediate downhole conditions. Their use 

complicates any 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 destroyed. Their mandated use in all new Class VI

wells would exclude use of other systems that may be fully adequate, more flexible, and 

allow more research data collection to take place on early wells.

146.89

(c) 

The logs cited here are too prescriptive. A noise log is outdated technology that is highly 

subjective in its interpretation. 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 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 reservoir 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 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 the confining 

zone fails will this be viable. Further, the “first formation” overlying 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 you are proposing monitoring in a suitable 

(permeable) rock interval above the confining zone, but that may not be in the first 

stratigraphically 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 apply in a regulatory 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 CO2 plume boundary? Is it a given saturation over a 

given thickness? Is it any detectable amplitude brightening on a reflection seismic image

or other geophysical indication? 

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 

reservoir assessment, modeling, and simulation based on data collection during injection 

and then specifically at closure, followed by five years after closure, 10 years after 

closure, and 15 years after closure. These suggested intervals have a basis in the changes 

seen in the 4D seismic as Sleipner that show demonstrable 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 other geophysical techniques, and three subsequent surveys at five-year intervals could

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

of four such example surveys (closure, +5, +10, and +15) and/or other appropriate

monitoring techniques, 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. To repeat, there is no basis for the suggested 50 years of monitoring.

(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?
Letter ID: 0180 

Commenter: Robert J. Finley 

Organization: Illinois State 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 carbon sequestration operations. Clearly, 

very significant efforts have been made, and input has been received on many 

issues to craft 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, 

Individual Response: EPA acknowledges the comment. Please see the remainder of EPA's 

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

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

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

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

Comment: 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. 

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 flexible approach, where operators of GS projects 

would develop and implement site-specific plans for delineating the AoR, testing and monitoring 

the site, performing corrective action, and post-injection site care. EPA believes that the plans—

which would be reviewed and approved by the Director and periodically updated throughout the 

life of the project—promote an ongoing dialogue between the operator and the Director that will 

encourage use of the most appropriate technologies 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 

1
Comment: 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 reality, the capillary entry pressure of a 

reservoir seal may be such that it prevents 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 limitation at §146.88(a) is an upper limit 

and provides a satisfactory margin of safety for all CO2 GS projects. EPA clarifies that the 

Director will evaluate all site data, including information collected 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 capillary 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 before failure (World Resources Institute, 2008). 

In addition, if there is any reason to believe that fracturing of the confining 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 reservoir 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 available 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 

2
separate requirements for information to be submitted with the permit application and before 

well construction is approved (at §146.82(a)) and information to be submitted before operation 

of the well is authorized (at §146.82(c)). 

EPA believes that this revision 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 injection well classes, which could help avoid 

confusion about how to meet the permitting requirements 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 modifications and additions that 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, comprehensive information about the site exists (e.g., 

from earlier geologic studies of the area), the Director may, at his/her discretion, allow its use in 

the site characterization for the 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 representative 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 Director authority to require the owner or 

operator to core other formations in the borehole if necessary to provide 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 injection 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 problematic here and elsewhere. Faults may be 

sealing, as in the case of many hydrocarbon traps, or they may be transmissive, 

especially in tensional stress regimes. In compressive regimes, and if similar 

faults form hydrocarbon trap boundaries, faults 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 fractures is appropriate for Class VI wells and is 

necessary to ensure containment of the injectate and that requiring the confining 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 successfully 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 

3
presence of faults or fractures. At sites where deep faults (even with little or no surface 

expression) are present, processing and interpreting data from multiple geophysical sensing 

methods has been shown to detect faults better than analysis 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 geologic 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 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 impossible given that a confining zone should not be permeable and 

therefore its testing with wireline or drillstem tools is highly questionable. 

Individual Response: EPA agrees that not all of the information listed at §146.82 of the 

proposed regulation will be available 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 information to be submitted before operation 

of the well is authorized (at §146.82(c)). 

EPA believes that this revision 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 injection well classes, which could help avoid 

confusion about how to meet the permitting requirements 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 modifications and additions that address the unique 

challenges and types of data collected for GS wells. 

EPA adds that the presence or absence of an economic 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 the suitability of the site, regardless of an 

economic incentive for gathering that data. 

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

Comment Code: 3140 2.1.4 Comments that the proposed geologic 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. 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 every formation in the area of a 

proposed site. 

Individual Response: The Agency believes that the requirement 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 and transport model development (e.g., by providing 

appropriate input parameters), and provide information needed to respond to any unexpected and 

unpermitted leaks outside of the injection zone. The 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 requires geochemical analysis of, at a minimum, the injection zone, 

confining zone, and all USDWs (§146.82(a)(6)). These geochemical tests 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 require geochemical analysis of additional 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, comprehensive information about the site exists (e.g., 

from earlier geologic studies of the area), the Director may, at his/her discretion, allow its use in 

the site characterization for the 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 representative 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 Director authority to require the owner or 

operator to core other formations in the borehole if necessary to provide 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 injection zone and confining system. 

Additionally, EPA acknowledges comments regarding the costs associated with thoroughly 

evaluating a potential GS site. The Agency believes the requirements for a thorough geologic site 

characterization for a GS project are necessary to protect USDWs from endangerment. 

5
Letter 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 date suggests that there may be both 

dissolution and precipitation of mineral phases as brine containing dissolved 

CO2 reacts with reservoir and confining layer rock. What is the standard for 

compatibility? If the apertures of microfractures are first enlarged but then 

carbonate or other minerals are expected to be reprecipitated, is that 

compatible? Much more appropriate would be to ask for the expected 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 confining zone. In response to 

comments and based on an evaluation of the proposed requirements, EPA revised subpart 

§146.82 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 information to be submitted before operation 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 with the materials used to construct 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 could 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) 

6
Modify this section to indicate that the confining zone is "reasonably 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 analogy to oil field or gas storage field 

performance. There is no mechanism to carry 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 which 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. 

Individual Response: The Agency believes that the requirement at §146.83(a)(2) that the 

confining zone be free of transmissive faults or fractures is appropriate for Class VI wells and is 

necessary to ensure containment of the injectate and that requiring the confining 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 successfully 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 where deep faults (even with little or no surface 

expression) are present, processing and interpreting data from multiple geophysical sensing 

methods has been shown to detect faults better than analysis of data from individual methods 

(Goussev et al, 2004). Drilling through faults or fractures with appropriate 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 storage reservoir. In some cases, the use of 

complementary drilling and geophysical methods 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 clarifies that §146.82(a)(3)(ii) requires the owner or operator to 

submit data on known or suspected faults and fractures (i.e., not all fractures). Other 

requirements for GS injection wells and sites can mitigate the potential impacts of unidentified 

fractures. These include limitations on injection pressures to avoid propagation of existing 

fractures in the confining zone (§146.88(a)), collection 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 initial 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) 

7
Comment: (b) 

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

to additional zones. If there are no formations in the stratigraphic column at a 

sequestration site which have been depleted 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 pressure dissipation". Is that what is 

meant here? I suggest this phrase be carefully reviewed and considered for 

deletion. 

Individual Response: EPA clarifies that the primary purpose of the requirement for 

identification of additional confining zones where 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 endangerment. The Agency acknowledges that the 

additional confining formations may also, in site-specific circumstances, further impede vertical 

fluid movement, provide additional sites for monitoring, 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 corrective action is required in the area of review? If a 

Class II well has been plugged in conformance 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. 

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

used on wells within the AoR to meet the requirements 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 performed pursuant to the approved AoR and corrective action plan, 

8
which affords the Director the discretion to require any additional information needed to ensure 

that all necessary corrective action is performed. 

EPA is developing guidance on AoR and corrective action at GS Class VI sites to assist owners 

or operators and Directors in evaluating requirements and proposed AoR and corrective action 

plans under §146.84. The guidance describes EPA's recommended approaches for the data to be 

considered in an initial AoR delineation, how to apply computational 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/groundwater/uic/wells_sequestration.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 whether computational modeling can address the 

lateral and vertical movement 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 both pressure driven fluid flow and 

density driven flow at plume boundaries that 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 potentially be sufficient to cause fluids to migrate. 

However, the capillary entry pressure of the confining layer may prevent this. 

As stated here, however, there is no accounting 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 predict 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 computational 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, hydrostatic pressure and capillary entry pressure. 

Multiphase models have been used by States and 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 recovery of oil and gas from petroleum-bearing formations, and 

more recently, CO2 in the subsurface. 

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

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling 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 would consider any potential fluid 

migration that may exist at the site. If site-specific geologic data indicate 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 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? 

Individual Response: EPA clarifies that corrosion-resistant 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 sufficient strength and be designed for the life of the 

sequestration project. Further, materials must meet standards listed in the rule and be compatible 

with fluids with which the materials may be expected to come into contact. 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 about 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 casing and cementing and §146.86(c)(2 and 3) for 

tubing and packer location and type. 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. 

10
Letter 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 requests size of casing and leaves out size 

of tubing while (vii) ask for specifications 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, usually in 30-foot or 60-foot increments, 

may be followed by reaming before returning 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. 

Individual Response: EPA agrees that, in some cases, such as the situation mentioned by the 

commenter, a deviation check may not be necessary. EPA has modified the GS rule at 

§146.87(a)(8) to require the owner or operator to submit a pre-operational testing plan that meets 

the requirements of §146.87. EPA adds that the Director would have discretion to approve a plan 

without deviation checks that addresses circumstances where these tests may not be practical or 

useful, such as those mentioned by the commenter. EPA encourages owners or operators to 

discuss these situations with the Director when planning the deviation testing. 

11
Letter 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 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-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 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. 

Individual Response: EPA disagrees that the listed surface casing logging requirements would 

provide inaccurate readings. Because the surface 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 this 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 logging and testing, per §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 every 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 and all analyses of the core material 

and that the cores themselves should either be retained by the operator for a 

period of time and/or the operator should (subsequently) submit the cores to a 

state geological survey or the U.S. Geological 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 cores 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 must take whole cores or sidewall cores of the 

injection zone and confining system and formation fluid samples from the injection zone(s), and 

12
must submit to the Director a detailed report prepared by a log analyst that includes: well log 

analyses (including well logs), core analyses, and formation fluid sample information...." 

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 all 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 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. 

Individual Response: EPA disagrees that the 30-day notification requirement is unreasonable. 

The 30-day notification mirrors the current requirement 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 protection 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/edits to rule language 

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

Comment: 146.88 

(a) 

Change first line to read: "Except during 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 injection pressure limitation. The final rule at 

§146.91(d)(2) also requires that the owner or operator notify the Director 30 days before 

performing stimulation during injection operations; this will provide an opportunity for the 

13
Director to review the owner or operator's plans 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 wellhead should not read a pressure above 

the injection pressure because there also exists the hydrostatic 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 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 injectate 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 the commenter suggests, must be considered in 

maintaining annulus pressure and that fluid density 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 required. A complete system of surface 

shutoff valves at the wellhead, in the supply pipeline, at the compression 

station, etc. is much more amenable to the intended safety requirement than a 

downhole system. The operator should be required to demonstrate adequate shutoff 

capacity 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 

require hydraulic 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 a hydraulic line in the annulus and the internal 

diameter restriction may prevent use of certain tools run to evaluate the well 

14
or to remediate downhole conditions. Their use complicates any 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 destroyed. Their mandated use in all new 

Class VI wells would exclude use of other 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 benefits of down-hole shut-off systems and 

considering additional research, EPA will not require 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 owners 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 from 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 buoyant nature of CO2 and the elevated injection pressures 

associated with GS increase the likelihood of an uncontrolled flow of CO2 out of the well. If 

CO2 does begin to flow back up an injection well, 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 devices 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 automatic surface shut-off devices instead of down-hole devices for 

onshore wells provides more flexibility to owners or operators when performing required 

mechanical integrity tests. Additionally, this requirement addresses 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) 

15
Comment: 146.89 

(c) 

The logs cited here are too prescriptive. A noise log is outdated technology 

that is highly subjective in its interpretation. 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 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. 

Individual Response: EPA believes that the MITs described 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 potential problems in the injection well system. EPA believes that the 

MITs described in §146.89(c) of the rule, including noise logs, 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 represent standard techniques 

that have been used successfully by the drilling industry and the UIC program for many years. 

For additional information, please see the discussion 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 the owner or operator to prepare and gain approval 

for a project-specific testing and monitoring plan that includes MITs under §146.90. EPA 

clarifies that the regulations allow the Director to require additional methods or, with the 

Administrator's approval, to approve the use of alternative MIT methods 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 external mechanical integrity at least once annually at §146.89(c). 

EPA believes this is justifiable for the protection of USDWs from endangerment given the 

unique nature of CO2 GS relative to other injection operations, including the potential corrosive 

impact of CO2 in the presence of water and impurities on well materials, the potential 

geomechanical impacts to well integrity due to CO2 phase changes, the temperature and pressure 

effects associated with injecting supercritical CO2, and the buoyant nature of the injected CO2. 

Because of the unknown long-term effects of CO2 GS, EPA chose a more conservative initial 

approach in the early stages of deployment for GS. 

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

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

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

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

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

Comment Code: 4650 2.6.5 CO2 plume and pressure front 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 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 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 the confining zone fails will this be 

viable. Further, the "first formation" overlying 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 you are proposing monitoring in a 

suitable (permeable) rock interval above the 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 pressure front in the receiving reservoir? 

What is their resolution and how does that apply in a regulatory 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 CO2 plume boundary? Is it a given saturation 

over a given thickness? Is it any detectable amplitude brightening on a 

reflection seismic image or other geophysical indication? 

Individual Response: EPA has revised the pressure monitoring requirement for the final rule. 

EPA believes that direct pressure measurements are appropriate and that 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 CO2 plume and pressure front. The 

owner or operator must use direct methods to monitor for pressure changes in the injection zone. 

Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down-hole 

CO2 detection tools) are also required unless the Director determines, based on site-specific 

geology, that such methods are not appropriate. 

17
EPA believes that pressure monitoring in the injection zone is necessary 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 modeling, evaluate predictions of 

plume movement, and target additional geochemical 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 appropriate 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 prove to be useful, but are not specified in the 

final regulation. Such methods may be an important 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-hole CO2 detection tools) 

unless the Director determines, based on site-specific geology that such methods are not 

appropriate. 

In response to comments regarding the 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 plume refers to a zone where there is a pressure 

differential sufficient to cause the movement of injected fluids or formation fluids into a USDW. 

The pressure front includes all areas wherein pressure is great enough to cause fluid movement 

into a USDW if a conduit were to exist. The calculation of the threshold pressure that defines the 

edge of the pressure front is dependent on properties of the injection and confining zones, 

including permeability, porosity, and compressibility, 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 front is site- and project-specific, and a single 

pressure value can not be provided for all sites. 

EPA is developing guidance on testing and monitoring to assist owners 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 recommended approaches for implementing a testing and monitoring 

plan, including pre-operational geophysical logging and testing of injection wells, MITs, 

injection well testing during operation, groundwater quality monitoring, tracking the CO2 plume 

and pressure front, and soil gas and surface air monitoring which may be required by the UIC 

Director for specific GS projects. The guidance can be found on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. In addition, in January 2009, 

DOE published a best practices manual entitled "Monitoring, Verification, 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-injection timeframe (seeking comment) 

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Comment: 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 reservoir assessment, modeling, and simulation 

based on data collection during injection and then specifically at closure, 

followed by five years after closure, 10 years after closure, and 15 years after 

closure. These suggested intervals have a basis in the changes seen in the 4D 

seismic as Sleipner that show demonstrable 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 other geophysical techniques, and three 

subsequent surveys at five-year intervals could document plume migration and 

would serve to validate reservoir simulation. If the total of four such example 

surveys (closure, +5, +10, and +15) and/or other appropriate monitoring 

techniques, 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. To repeat, there is no basis for the suggested 50 

years of monitoring. 

Individual Response: EPA disagrees that there is no basis for the 50 year timeframe. In 

determining the post-injection site care-timeframe for the proposed regulation, EPA reviewed 

industry reports, existing environmental programs, and initial GS research studies. EPA provided 

a synthesis of pertinent results from GS modeling studies in the preamble to the proposed 

regulation. Further explanation of this analysis was included in an EPA-prepared background 

document that is available in the federal docket, titled "Computational Modeling of Underground 

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

Underground Sources of Drinking Water." Based on review of these studies, modeling results 

indicate that the CO2 plume stabilization may occur on the timeframe of 10-100 years after the 

cessation of injection. EPA believes that a 50-year default post-injection site care timeframe is a 

reasonable midpoint for most GS projects and available data, including data submitted by 

commenters, do not support a different default timeframe, and has retained this in the final 

regulation. 

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

timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. For this reason, the Class VI rule offers owners or operators flexibility 

regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten 

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or 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 appropriate if it ensures non-endangerment of USDWs 

pursuant to requirements at §146.93(c). 

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

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

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

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

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

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

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

impacts. 

EPA clarifies that, throughout the post-injection site care timeframe, 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 performing 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-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 individual UIC Directors, in consultation 

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

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

consultation with all potentially impacted parties. 

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

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

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

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

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 proposed well plugging plans and post-injection site 

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care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells; perform 

post-injection monitoring; demonstrate non endangerment; and perform site closure activities. 

The guidance will be available at 

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