2.4 – 2.5 – Responses to Public Comments on Operating Requirements and Mechanical 

Integrity Testing

This file contains responses to public comments on operating requirements and 

mechanical integrity testing (comment codes 4000 to 4546). This section includes 

comments on injection pressure limitations, the use of hydraulic fracturing for well 

stimulation, the use of downhole shut-off devices, corrosion monitoring and control, 

and the use of tracers. It also includes comments on the testing of the wells for internal 

and external mechanical integrity.

The table below presents all of the EPA-assigned comment codes that are included in 

this section of the comment and response summary. Use the bookmarks in the PDF to 

move among the comment codes. 

Topics included in this summary and associated comment codes

Topic Code

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

2.4.1 Injection parameters 4100

2.4.1.1 Injection pressure limitations 4110

2.4.1.2 Allowing hydraulic fracturing during GS 4120

2.4.1.3 Appropriateness of using fracturing for well stimulation 4130

2.4.1.4 Use of fracturing for GS in specific geologic settings 4140

2.4.2 Down-hole shut-off valves in GS wells 4200

2.4.3 Corrosion monitoring and control 4250

2.4.4 Injection Depth 4300

2.4.4.1 Injection beneath the lowermost formation containing a USDW 4320

2.4.4.1.1 Comments in favor of requiring injection below the lowermost USDW 4322

2.4.4.1.2 Comments opposed to requiring injection below the lowermost USDW 4324

2.4.4.2 Minimum injection depth 4340

2.4.4.2.1 Comments in favor of setting a minimum injection depth 4342

2.4.4.2.2 Comments opposed to setting a minimum injection depth 4344

2.4.4.3 Allowing injection above or between USDWs 4400

2.4.4.3.1 Comments in favor of allowing injection above/between USDWs in certain 

circumstances

4410

2.4.4.3.2 Comments opposing injection above/between USDWs in all cases 4420

2.4.4.3.3 Injection into coal seams above USDWs 4430

2.4.4.3.4 Injection into organic-rich shales above USDWs 4440

2.4.4.4 Use of aquifer exemptions 4450

2.4.4.4.1 Comments in favor of allowing aquifer exemptions in certain circumstances 4460

2.4.4.4.2 Comments opposing aquifer exemptions in all cases 4470

2.4.4.4.3 Under what conditions aquifer exemptions should be approved? (No comments 

were submitted for this topic.)

4480

2.4.5 Use of tracers and potential impact on human health or ecosystems 4490

2.5 Proposed Mechanical Integrity Testing (MIT) Requirements (40 CFR 146.89) 4500

2.5.1 Continuous internal mechanical integrity monitoring 4520

2.5.2 Proposed external MIT requirements 4540

2.5.2.1 MIT procedures and methods for GS 4543

2.5.2.2 MIT frequency 4546
Every comment on these topic areas and the associated response is included in this 

summary; there is some repetition where multiple commenters made the same 

comment.

Responses to letters from individual commenters or organizations are also available in 

the rulemaking docket.
Comment Code: 4000 2.4 Proposed Injection Well Operating Requirements (40 CFR 146.88) 

Individual Comments

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24747

Comment: 5. EPA should provide more flexibiilty in operation. For example, allow an EOR 

Response: EPA believes the operating requirements for Class VI wells are necessary in order to

protect USDWs from endangerment by providing multiple safeguards to ensure that well integrity,

containment of fluids within the injection zone, and that the integrity of the confining zone is not

compromised. Some of the operating requirements in the GS regulation (e.g., pressure limitations or

annulus pressure requirements) are consistent with those for other injection well types, while other

requirements (e.g., use of automatic shut-off systems or tracers at the Director's discretion) are

tailored to directly address the potential for large volumes of CO2 to be injected, among other

factors.

Commenter Name: John Hanger Letter ID: 0130

Commenter Organization: Pennsylvania Dept. of Env. Protection Comment ID: 21507

Comment: Proposed Injection Well Operating Requirements 

-Appropriate deed restrictions and surface controls should be required to be 

implemented by the owner/operator to prevent another person from compromising 

the integrity of the confinement zone. 

Response: EPA clarifies that issues related to deed restrictions and surface controls are outside the

scope of the GS rulemaking. However, EPA agrees that the impacts of multiple operators injecting

into hydraulically connected formations should be accounted for by the Director when determining

whether to approve a Class VI permit application. EPA adds that, as part of the AoR evaluation

process required at §146.84, the operator must demonstrate, in the proposed AoR and corrective

action plan, to the satisfaction of the Director that the modeled AoR will be based on detailed

geologic data collected on the site and includes consideration of existing conditions. EPA anticipates

that, where multiple operators are involved, the Director would not approve modeling that did not

account for the geochemical or pressure changes, including interactions with native fluids that may

result from all injections into a formation or a series of hydraulically connected formations.

Commenter Name: James Dooley Letter ID: 0156

Commenter Organization: Joint Global Change Research Institute, Pacific

Northwest National Laboratory

Comment ID:

22648

Comment: o Page 43538. Owners and operators of Class VI wells are required to install 

and use continuous recording devices to monitor a number of critical performance 

variables. The rule does not specify how long these data are to be retained and 

who has access to them. 

Response: The GS regulation at §146.91(f) requires injection well operators to retain monitoring

records for ten years after the data is collected. The Director has the authority to request this data.
Commenter Name: Michael Mudd Letter ID: 0167

Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 22468

Comment: A-4 Proposed Injection Well Operating Requirements III-A-4 Class I wells are 

typically required to maintain an annular-fluid pressure that is greater than 

the injection tubing pressure to prevent outward leakage from the injection 

tubing. Typically, these wells operate at pressures much lower than CO2 

injection wells. This same requirement imposed on CO2 injection wells would 

require specialized high-pressure equipment to maintain the required pressure 

differential on the annular fluid. 

Response: EPA believes that maintaining an annulus pressure that is higher than the injection

pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the annulus fluid

will move into the tubing, rather than the injectate moving out of the tubing and potentially along the

outside of the well. EPA believes this requirement is appropriate for Class VI wells given the

potential high volumes and supercritical nature of the CO2 injectate, potential geomechanical

stresses in the wellbore, and the potential for movement of the CO2 in the event of a mechanical

integrity loss.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24185

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(f)(3) 

API Comments: (3) Notify the Director within 24 hours OF DISCOVERY; 

No rationale provided 

Response: The final rule text at §146.88(f) now reads, "If a shutdown (i.e., down-hole or at the

surface) is triggered or a loss of mechanical integrity is discovered." Therefore the notice required at

§146.88(f)(3) must be provided within 24 hours of an automatic shut-off device being triggered or a

loss of mechanical integrity being discovered. EPA believes this provision is necessary to ensure

timely response to potential USDW endangerment.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23821

Comment: H. NON-COMPLIANCE 

If a site is not in compliance, there should be no requirement that injection 

cease immediately, unless an imminent threat of harm to human health or the 

environment is posed. 

Response: EPA disagrees with the commenter, and believes that the requirement at §146.88(f) to

cease injection immediately upon indication of a mechanical integrity loss is necessary and

appropriate because loss of mechanical integrity can signal problems which could lead to a loss of

integrity or well failure and potential leaks of CO2 that may cause endangerment to a USDW. While

there may be circumstances in which a well appears to lack mechanical integrity but actually poses

no risk, such a determination cannot be made without an investigation. It would be inadequate for
purposes of protecting USDWs from endangerment to require that injection cease only when there

was an imminent threat of harm to human health or environment.

Commenter Name: Robert J. Finley Letter ID: 0180

Commenter Organization: Illinois State Geological Survey Comment ID: 23635

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: 146.88 

(a) 

Change first line to read: "Except during stimulation and fracture breakdown 

pressure testing". 

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 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.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23740

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Part 146.88(b) AWWA recommends revising this part to read: 

Injection of the carbon dioxide stream between the outermost casing protecting 

USDWs and the well bore is prohibited. 

Response: EPA retains the provision as proposed, and clarifies that injection between the casing and

the well bore is prohibited. This is consistent with requirements for other injection well classes in the

UIC program.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23741

Comment: Part 146.88(d) AWWA recommends that the final rule require mandatory 

implementation of a Supervisory Control and Data Acquisition (SCADA) system as 

part of the geologic carbon sequestration system. This system would allow for 

continuous monitoring and storage of the data associated with the operation of 

the injection well. Owner/operators would be able to review data trends and 

detect anomalies or potential problems before they occur. This SCADA system 

should also be tied to a carbon dioxide detector to alarm and shut off the well 

in the event that carbon dioxide is detected above a pre-set level. 

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

of continuous computer-based monitoring device that will be connected to alarms and the shut-off

system. EPA does not believe it is necessary to specify what type of equipment is to be used to
trigger the shut-off system. Instead, the regulation allows the owner or operator some flexibility in

deciding what equipment and alarms should be installed to allow site specific flexibility and to make

use of improvements in technology. EPA believes that the technology for continuous monitoring is

available and is currently in fairly wide use. The combination of computer-driven continuous

pressure monitoring linked to an automatic injection shut-off provides maximum protection of

USDWs from endangerment and provides the earliest warning to owners or operators that well

repairs need to be performed.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24473

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(f)(3) 

Proposed CCS Group Recommendations: (3) Notify the Director within 24 hours OF 

DISCOVERY; 

Basis for CCS Group Comments: Clarifying revision to (3) will make compliance 

feasible for operators. 

Response: The final rule text at §146.88(f) now reads, "If a shutdown (i.e., down-hole or at the

surface) is triggered or a loss of mechanical integrity is discovered." Therefore the notice required at

§146.88(f)(3) must be provided within 24 hours of an automatic shut-off device being triggered or a

loss of mechanical integrity being discovered. EPA believes this provision is necessary to ensure

timely response to potential USDW endangerment.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24697

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(f)(3) 

Anadarko Petroleum Corporation (APC) Comments: (3) Notify the Director within 24 

hours OF DISCOVERY; 

No rationale provided 

Response: The final rule text at §146.88(f) now reads, "If a shutdown (i.e., down-hole or at the

surface) is triggered or a loss of mechanical integrity is discovered." Therefore the notice required at

§146.88(f)(3) must be provided within 24 hours of an automatic shut-off device being triggered or a

loss of mechanical integrity being discovered. EPA believes this provision is necessary to ensure

timely response to potential USDW endangerment.

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21673

Other EPA Comment Codes and Descriptions: 3800 2.3 Proposed Injection Well Construction

Requirements (40 CFR 146.86) 

Comment: (1) Importance of Well Integrity 
EPA has appropriately recognized that wells are a fundamental component of a 

secure system for the long-term geologic sequestration of CO2. As such, applying 

appropriate well design, construction & operating requirements is critical to 

the delivery of secure storage. As previously discussed, oil and gas operators 

have nearly four decades of experience, via past and existing production 

operations, in constructing and operating CO2 EOR/EGR wells in a safe and secure 

manner. Notably, Class II requirements have proven to be effective in ensuring 

the non-endangerment of USDWs. Therefore, HEI believes it would be prudent to 

rely upon this extensive existing regulatory and industry experience and 

knowledge in setting Class VI requirements for wells that inject CO2 for long 

term sequestration. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of enhanced recovery and that many of the wells used for ER may be suitable for GS.

However, EPA believes that GS is sufficiently different from Class II ER operations to warrant the

tailored construction requirements for Class VI wells at §146.86. For example, the volume of CO2

anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir

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

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

Therefore, Class VI GS reservoir pressures will increase more in comparison to Class II ER during

the injection phase of the GS project.

The final GS rule, at §146.81(c), allows the construction of these wells to be grandfathered, provided

the owner or operator can demonstrate to the Director that the wells were engineered and constructed

to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at

§146.86(b) and §146.87(a). Only the cemented-in-place construction requirements would be

grandfathered under the final GS rule; following conversion, these wells must be permitted as Class

VI wells and be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection

site care and site closure requirements in the final GS rule. 

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

Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI

transition. The guidance describes the methods available for the Director to determine the risk posed

to USDWs from a GS/ER project, and how the Director may determine if a project should be

regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's web site,

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

Regarding operational requirements, EPA believes such requirements are necessary for Class VI

wells to protect USDWs from endangerment by providing multiple safeguards to ensure that well

integrity, containment of fluids within the injection zone, and that the integrity of the confining zone

is not compromised. Some of the operating requirements in the GS regulation (e.g., pressure

limitations or annulus pressure requirements) are consistent with those for other injection well types,

while other requirements (e.g., use of automatic shut-off systems or tracers at the Director's

discretion) are tailored to directly address the potential for large volumes of CO2 to be injected,

among other factors.

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21684
Other EPA Comment Codes and Descriptions: 4130 2.4.1.3 Appropriateness of using fracturing

for well stimulation (seeking comment) 

Comment: number of penetrations through the caprock. There are other options to optimize 

injectivity as well that include, but should not be limited to, hydraulic 

fracture treatments, multiple injection points along the wellbore and open hole 

completions. 

Response: EPA agrees that hydraulic fracturing is one of several stimulation technologies available

to improve wellbore and formation injectivity. The final rule allows the use of hydraulic fracturing at

GS sites, if approved by the Director. 

EPA clarifies that all stimulation for Class VI wells, including hydraulic fracturing, must be

approved by the Director. Owners or operators must submit a proposed stimulation program as part

of the permit application under §146.82(a)(9); the plan must demonstrate that any stimulation

activities will not compromise the integrity of the confining zone. The Director will evaluate the

owner or operator's proposed stimulation plan in the context of all information about the site, and the

owner or operator must perform stimulation only as approved. 

The final rule also requires that the owner or operator notify the Director 30 days before performing

stimulation during injection operations (§146.91(d)(2)); this will provide an additional opportunity

for the 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.

EPA also agrees that multiple and open hole completions are also acceptable manners to improve

injectivity. Class VI wells with these types of completions are acceptable, provided all other

construction requirements at §146.86 are met.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21718

Other EPA Comment Codes and Descriptions: 3800 2.3 Proposed Injection Well Construction

Requirements (40 CFR 146.86) 

Comment: (1) Importance of Well Integrity 

EPA has appropriately recognized that wells are a fundamental component of a 

secure system for the long-term geologic sequestration of CO2. As such, applying 

appropriate well design, construction & operating requirements is critical to 

the delivery of secure storage. As previously discussed, oil and gas operators 

have nearly four decades of experience, via past and existing production 

operations, in constructing and operating CO2 EOR/EGR wells in a safe and secure 

manner. Notably, Class II requirements have proven to be effective in ensuring 

the non-endangerment of USDWs. Therefore, BP believes it would be prudent to 

rely upon this extensive existing regulatory and industry experience and 

knowledge in setting Class VI requirements for wells that inject CO2 for long 

term sequestration. 

Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for

the purpose of enhanced recovery and that many of the wells used for ER may be suitable for GS.

EPA believes that GS is sufficiently different from Class II ER operations to warrant the tailored
construction requirements for Class VI wells at §146.86. For example, the volume of CO2

anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir

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

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

Therefore, Class VI GS reservoir pressures will increase more in comparison to Class II ER during

the injection phase of the GS project.

The final GS rule, at §146.81(c), allows the construction of these wells to be grandfathered, provided

the owner or operator can demonstrate to the Director that the wells were engineered and constructed

to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at

§146.86(b) and §146.87(a). Only the cemented-in-place construction requirements would be

grandfathered under the final GS rule; following conversion, these wells must be permitted as Class

VI wells and be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection

site care and site closure requirements in the final GS rule. 

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

Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI

transition. The guidance describes the methods available for the Director to determine the risk posed

to USDWs from a GS/ER project, and how the Director may determine if a project should be

regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's web site,

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

Regarding operational requirements, EPA believes such requirements for Class VI wells are

necessary to protect USDWs from endangerment by providing multiple safeguards to ensure that

well integrity, containment of fluids within the injection zone, and that the integrity of the confining

zone is not compromised. Some of the operating requirements in the GS regulation (e.g., pressure

limitations or annulus pressure requirements) are consistent with those for other injection well types,

while other requirements (e.g., use of automatic shut-off systems or tracers at the Director's

discretion) are tailored to directly address the potential for large volumes of CO2 to be injected,

among other factors.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21735

Other EPA Comment Codes and Descriptions: 4130 2.4.1.3 Appropriateness of using fracturing

for well stimulation (seeking comment) 

Comment: limits the number of penetrations through the caprock. There are other options 

to optimize injectivity as well that include, but should not be limited to, 

hydraulic fracture treatments, multiple injection points along the wellbore and 

open hole completions. 

Response: EPA agrees that hydraulic fracturing is one of several stimulation technologies available

to improve wellbore and formation injectivity. The final rule allows the use of hydraulic fracturing at

GS sites, if approved by the Director. 

EPA clarifies that all stimulation of Class VI wells, including hydraulic fracturing, must be approved

by the Director. Owners or operators must submit a proposed stimulation program as part of the

permit application under §146.82(a)(9); the plan must demonstrate that any stimulation activities will

not compromise the integrity of the confining zone. The Director will evaluate the owner or

operator's proposed stimulation plan in the context of all information about the site, and the owner or
operator must perform stimulation only as approved. 

The final rule also requires that the owner or operator notify the Director 30 days before performing

stimulation during injection operations (§146.91(d)(2)); this will provide an additional opportunity

for the 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.

EPA also agrees that multiple and open hole completions are also acceptable manners to improve

injectivity. Class VI wells with these types of completions are acceptable, provided all other

construction requirements at §146.86 are met.

Commenter Name: Andrew Duguid Letter ID: 0226

Commenter Organization: Schlumberger Carbon Services Comment ID: 24050

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Proposed Rule: (b) Injection between the outermost casing protecting USDWs and 

the well bore is prohibited. 

Schlumberger Suggested Revision: (b) Injection of the CO2 stream between the 

outermost casing protecting USDWs and the well bore is prohibited. 

Schlumberger Rationale: - 

Response: EPA retains the provision as proposed, and clarifies that injection between the casing and

the well bore is prohibited. This is consistent with requirements for other injection well classes in the

UIC program.

Commenter Name: Andrew Duguid Letter ID: 0226

Commenter Organization: Schlumberger Carbon Services Comment ID: 24051

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Proposed Rule: (c) The owner or operator must fill the annulus between the 

tubing and the long string casing with a non-corrosive fluid approved by the 

Director. The owner or operator must maintain on the annulus a pressure that 

exceeds the operating injection pressure, unless the Director determines that 

such requirement might harm the integrity of the well. 

Schlumberger Suggested Revision: (c) The owner or operator must fill the annulus 

between the tubing and the long string casing with a non-corrosive fluid 

approved by the Director. 

Schlumberger Rationale: Industry experience with the Class II UIC program does 

not support this requirement. 

Response: EPA believes that maintaining an annulus pressure that is higher than the injection

pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the annulus fluid

will move into the tubing, rather than the injectate moving out of the tubing and potentially along the
outside of the well. EPA believes this requirement is appropriate and necessary for Class VI wells

given the potential high volumes and supercritical nature of the CO2 injectate, potential

geomechanical stresses in the wellbore, and the potential for movement of the CO2 in the event of a

mechanical integrity loss.

Commenter Name: Andrew Duguid Letter ID: 0226

Commenter Organization: Schlumberger Carbon Services Comment ID: 24052

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Proposed Rule: (3) Notify the Director within 24 hours 

Schlumberger Suggested Revision: (3) Notify the Director within 24 hours of 

discovery; 

Schlumberger Rationale: - 

Response: The final rule text at §146.88(f) now reads, "If a shutdown (i.e., down-hole or at the

surface) is triggered or a loss of mechanical integrity is discovered." Therefore the notice required at

§146.88(f)(3) must be provided within 24 hours of an automatic shut-off device being triggered or a

loss of mechanical integrity being discovered. EPA believes this provision is necessary to ensure

timely response to potential USDW endangerment.

Commenter Name: M. Granger Morgan Letter ID: 0233

Commenter Organization: Carnegie Mellon University on behalf of the CCS

Reg Project

Comment ID:

21912

Comment: 21. Performance standards: We support EPA’s general approach of establishing 

performance standards for acceptable operation, but strongly caution that action 

thresholds or performance standards established for the Class VI rule should not 

be expressed as quantitative requirements for maximum leakage (or minimum 

retention) from the injection zone. Current monitoring methods cannot quantify 

low-level leakage rates or volume retained at reasonable cost or with needed 

precision, as detailed in Chapter 4 of the attached report [SEE PDF TO VIEW THE REPORT].

Thus, other 

performance measures are needed. 

Response: EPA clarifies that the GS rule does not set specific quantitative requirements for

maximum leakage (or minimum retention) of CO2 from the injection zone. Rather, the intent of the

rule is to ensure that injection wells are permitted, sited, constructed, operated, monitored, and

plugged in a manner that does not endanger USDWs. The rule affords the Director discretion and

flexibility to set permit conditions to ensure that USDWs are protected from the impacts of GS

projects. 

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24914

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(f) 
EPA Proposal: (1) Immediately cease injection; 

(2) Take all steps reasonably necessary to determine whether there may have been 

a release of the injected carbon dioxide stream into any unauthorized zone; 

(3) Notify the Director within 24 hours; 

(4) Restore and demonstrate mechanical integrity to the satisfaction of the 

Director prior to resuming injection; and 

(5) Notify the Director when injection can be expected to resume. 

GWPC Recommendations: Support the proposed EPA language for (1), (2), and (5) 

(3) Notify the Director within 24 hours of discovery; 

(4) Restore and demonstrate mechanical integrity to the satisfaction of the 

director as soon as practicable and prior to resuming injection. 

Rationale: Needs to be reasonable and allow for time following discovery. 

It was felt that some timeframe for restoration of mechanical integrity should 

be added to (4) 

Response: The final rule text at §146.88(f) now reads, "If a shutdown (i.e., down-hole or at the

surface) is triggered or a loss of mechanical integrity is discovered." Therefore the notice required at

§146.88(f)(3) must be provided within 24 hours of an automatic shut-off device being triggered or a

loss of mechanical integrity being discovered. EPA believes this provision is necessary to ensure

timely response to potential USDW endangerment.

Commenter Name: Craig Hart Letter ID: 0261

Commenter Organization: Alston & Bird LLP Comment ID: 22988

Other EPA Comment Codes and Descriptions: 4710 2.7.1 Proposed submissions required for

permit applications (seeking comment) 

Comment: Other U.S. environmental laws, such as the Toxic Substances Control Act, also 

provide precedent for a streamline permitting approach in other contexts.[FN7] 

Options for a Streamline Review Procedure 

A common feature of streamline permitting schemes is a quantified limit, which 

in the case of CCS, would likely be a volume limit. The advantages of quantified 

volume limit include that it provides greater certainty for research 

organizations and allows EPA to allocate resources to higher volume CCS 

injections that pose more significant risks. 

While no specific volume limit is suggested here, EPA should consider several 

factors for setting such a limit. A volume limit should be differentiated base 

on type of formation, site pressure, and other site-specific conditions. Such a 

limit could change (likely increase) along with our knowledge of a particular 

formation and experience with CO2 injections for purposes of permanent 

sequestration generally. Finally, in addition to considerations relating to 

protection of drinking water sources, a volume limit should be based on the 

needs of advancing research and the risks to health and safety, including 

workers, the general population, flora and fauna. CCS assessment models have 
been developed by our national laboratories specifically to address these kinds 

of risks.[FN8] 

[FN7] TSCA governs the manufacture, processing, use, distribution in commerce, and 

disposal of chemical substances and mixtures. It provides for varying levels of 

expedited review and exemption from regulations in qualifying research, low 

volume commercial production, and low release low exposure commercial 

production. See Elizabeth Brown et al., A Practitioner's Guide to the Toxic 

Substance Control Act, Environmental Law Institute, 1999. 

[FN8] See Curtis M. Oldenburg and Steven L. Bryant, Certification Framework for 

Geologic CO2 Storage, Sixth Annual Conference on Carbon Capture and 

Sequestration, National Energy Technology Laboratory, Pittsburgh, PA, May 7-10, 

2007 available at www.netl.doe.govjpublicationsjproceedingsj07jcarbon 

seqjdatajpapersjtue_062.pdf; Curtis M. Oldenburg, Steven L. Bryant, JeanPhilippe Nicot, and Ying Zhang, Certification Framework for Geologic Carbon 

Sequestration Based on Effective Trapping, Seventh Annual Conference on Carbon 

Capture and Sequestration, National Energy Technology Laboratory, Pittsburgh, 

PA, May 5-8, 2008; Curtis M. Oldenburg, Steven L. Bryant, Jean-Philippe Nicot, 

Certification Framework for Geologic Carbon Sequestration Based on Effective 

Trapping (forthcoming 2008). 

Response: As described above, EPA disagrees with the suggestion that it should streamline the

approval process for small-volume operators. EPA believes that the information required to be

submitted with the permit application under §146.82 is necessary and appropriate to provide

permitting authorities sufficient information on which to base informed decisions about establishing

permit conditions and granting permits. The purpose of these requirements is to protect USDWs

from endangerment, and like large-volume operations, small-volume operations must be permitted

and operated in manner that is protective of USDWs.

EPA disagrees with the suggestion to set a volume limit. EPA believes that the potentially wider

range of injection scenarios, formation types, and other site-specific factors necessitate a sitespecific approach, and permit limits that are based on the unique geology of the site. The injection

pressure limit for each GS project will be based on site-specific conditions, and be informed by data

on the injection zone.

Commenter Name: Mike Moore Letter ID: 0532

Commenter Organization: North American Carbon Capture and Storage

Association (NACCSA)

Comment ID:

21367

Other EPA Comment Codes and Descriptions: 4600 2.6 Proposed Plume and Pressure Front

Monitoring Requirements (40 CFR 146.90) 

Comment: The second area of concern is the proposed rule's treatment of CCS operations 

and monitoring. The proposed rule would require CCS wells to meet or exceed the 

operating standards of industrial and hazardous waste wells in many cases. NACSA 

believes that such treatment is not justified by the attributes of carbon 

dioxide. Also the director would have discretion without any guidance to require 

Response: The Agency recognizes that while there are similarities between injection of wastes for

disposal (Class I) and GS (Class VI), there are significant differences as well. Important unique
considerations for GS include the buoyancy of CO2, its corrosivity when in contact with water, its

low viscosity (i.e., high mobility), and the very large injection volumes that are anticipated. There is

also a degree of uncertainty regarding the behavior of large volumes of CO2 in the subsurface after

injection. 

Given these characteristics of anticipated GS projects, EPA believes that the monitoring

requirements at §146.90 are justified to provide early warning of any unforeseen fluid movement or

problems with the injection well that might endanger USDWs. EPA emphasizes that monitoring of

injection activities will be an important component of every GS project. Monitoring associated with

injection wells and the movement of the CO2 plume is necessary to verify that the injectate is

confined in the target formations and does not endanger USDWs.

EPA believes the operating requirements for Class VI wells are necessary and provide multiple

safeguards to ensure that well integrity, containment of fluids within the injection zone, and that the

integrity of the confining zone is not compromised. Some of the operating requirements in the GS

regulation (e.g., pressure limitations or annulus pressure requirements) are consistent with those for

other injection well types, while other requirements (e.g., use of automatic shut-off systems or

tracers at the Director's discretion) are tailored to directly address the potential for large volumes of

CO2 to be injected, among other factors. 

The requirements for GS projects are tailored to address the unique issues associated with GS

including large injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of

water, the potential presence of impurities in captured CO2, and its mobility within subsurface

geologic formations. EPA also believes these requirements are appropriate for Class VI wells given

the potential geomechanical stresses in the wellbore, and the potential for movement of the CO2 in

the event of a mechanical integrity loss.

Commenter Name: Olon Plunk Letter ID: 0536

Commenter Organization: Xcel Energy Comment ID: 21378

Other EPA Comment Codes and Descriptions: 3100 2.1 Proposed Geologic Siting Requirements

(40 CFR 146.83); 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 146.86);

5000 2.8 Proposed Well Plugging and Post-Injection Site Care Requirements 

Comment: We believe there must be suitable CO2 injection plans backed by seismic surveys, 

multi dimensional modeling simulations and formation testing. 

We recognize the overriding importance of well design and construction that 

assures well integrity. We believe there must be a sound operations management 

program including appropriate monitoring and corrective actions that are 

prepared and implemented by experts in the field. 

We recognize both the local and national interest in providing effective post 

injection site care and closure and demonstrating adequate financial 

responsibility for these activities. While agreeing with supporting all of these 

important program elements, I would like to add a few words of caution. 

Response: EPA acknowledges the comment. The GS requirements are designed to ensure protection

of USDWs from endangerment by requiring that injection wells are permitted, sited, constructed,

operated, monitored, and plugged in a manner that does not endanger USDWs. Appropriately

designed and constructed wells are necessary to prevent endangerment to USDWs and maintain
integrity of the well throughout the lifetime of a GS project. This is the foundation of the

requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 146.87. 

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

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

provides recommendations characterizing the regional geology and hydrogeology of a proposed GS

site as well as performing the necessary geochemical, geomechanical, and geophysical analyses of

the injection and confining zone. EPA expects that this guidance will assist permit writers in

evaluating this information. The guidance can be found on EPA’s website at

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

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

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

provides recommendations characterizing the regional geology and hydrogeology of a proposed GS

site as well as performing the necessary geochemical, geomechanical, and geophysical analyses of

the injection and confining zone. EPA expects that this guidance will assist permit writers in

evaluating this information. The guidance can be found on EPA’s website at

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

Comment Code: 4100 2.4.1 Injection parameters 

Individual Comments

Commenter Name: Michael H. Cochran Letter ID:

0108

Commenter Organization: Bureau of Water, Division of Environment, Kansas

Department of Health & Environment (KDHE)

Comment

ID: 21977

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

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

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

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

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

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

Commenter Name: Michael H. Cochran Letter ID:

0108

Commenter Organization: Bureau of Water, Division of Environment, Kansas

Department of Health & Environment (KDHE)

Comment

ID: 21978

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

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

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

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

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

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

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

of continuous computer-based monitoring device that will be connected to alarms and the shut-off
system. EPA does not believe it is necessary to specify what type of equipment is to be used to

trigger the shut-off system. Instead, the regulation allows the owner or operator some flexibility in

deciding what equipment and alarms should be installed to allow site specific flexibility and to make

use of improvements in technology. EPA believes that the technology for continuous monitoring is

available and is currently in fairly wide use. The combination of computer-driven continuous

pressure monitoring linked to an automatic injection shut-off provides maximum protection of

USDWs from endangerment and provides the earliest warning to owners or operators that well

repairs need to be performed.

Commenter Name: Steven Pirner Letter ID: 0153

Commenter Organization: South Dakota Department of Environment and

Natural Resources

Comment ID:

22150

Comment: 146.88 Injection well requirements - (c) the annulus pressure needs to exceed 

the injection pressure - don't know why, as long as there is enough difference 

so sensors/gauges can indicate when something goes wrong. 

Response: EPA believes that maintaining an annulus pressure that is higher than the injection

pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the annulus fluid

will move into the tubing, rather than the injectate moving out of the tubing and potentially along the

outside of the well. EPA believes this requirement is appropriate for Class VI wells given the

potential high volumes and supercritical nature of the CO2 injectate, potential geomechanical

stresses in the wellbore, and the potential for movement of the CO2 in the event of a mechanical

integrity loss.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24181

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(b) 

API Comments: Injection OF THE CO2 STREAM between the outermost casing protecting

USDWSs and the well bore is prohibited. 

Rationale: Routine injection into zones other than the target interval(s) should be prohibited;

however, wording of this requirement is not clear as to which interval is being addressed. An

absolute prohibition on injection into this annulus may also limit diagnostic options that could be

useful. 

Response: EPA retains the provision as proposed, and clarifies that injection between the casing and

the well bore is prohibited. This is consistent with requirements for other injection well classes.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24182

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(c) 

API Comments: (c) The owner or operator must fill the annulus between the tubing 
and the long string casing with a non-corrosive fluid approved by the Director. 

The owner or operator must maintain on the annulus a pressure that exceeds the 

operating injection pressure, unless the Director determines that such 

requirement might harm the integrity of the well. A POSITIVE PRESSURE ON THE 

ANNULUS. 

Rationale: Industry experience with the Class II UIC program does not support 

this requirement. 

Positive annular pressure that exceeds the operating injection pressure is not 

necessary because a leak from tubing to annulus does not have the same 

implications as in a Class I hazardous situation. 

Response: EPA believes that maintaining an annulus pressure that is higher than the injection

pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the annulus fluid

will move into the tubing, rather than the injectate moving out of the tubing and potentially along the

outside of the well. EPA believes this requirement is appropriate for Class VI wells given the

potential high volumes and supercritical nature of the CO2 injectate, potential geomechanical

stresses in the wellbore, and the potential for movement of the CO2 in the event of a mechanical

integrity loss.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23861

Comment: With respect to specific well operating requirements, we reiterate the 

importance of maintaining reasonable standards that take into account that CCS 

injection will differ from other injection activities. For instance, Class I 

wells typically must maintain an annular-fluid pressure greater than the 

injection tubing pressure to prevent outward leakage from the injection tubing. 

Typically, these wells operate at pressures much lower than CO2 injection wells. 

This same requirement imposed on CO2 injection wells would require specialized 

high-pressure equipment to maintain the required pressure differential on the 

annular fluid. EPA also recommends as a possible safety device in CO2 injection 

Response: EPA believes that maintaining an annulus pressure that is higher than the injection

pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the annulus fluid

will move into the tubing, rather than the injectate moving out of the tubing and potentially along the

outside of the well. EPA believes this requirement is appropriate for Class VI wells given the

potential high volumes and supercritical nature of the CO2 injectate, potential geomechanical

stresses in the wellbore, and the potential for movement of the CO2 in the event of a mechanical

integrity loss.

Commenter Name: Robert J. Finley Letter ID: 0180

Commenter Organization: Illinois State Geological Survey Comment ID: 23636

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. 

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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24345

Comment: 2. Pressurized Annulus 

The proposed rule would require a pressurized annulus with an annulus pressure 

exceeding the pressure in the injection tube. While we support the proposed 

requirement for a pressurized annulus, we oppose the requirement that annulus 

pressure exceed injection tube pressure. 

The concept that annulus pressure should exceed injection tube pressure was 

introduced in the context of hazardous waste injection, where it reflected an 

extreme sensitivity to even the most remote possibility of a release of 

hazardous waste (the requirement was designed to ensure that injection tube 

leaks would cause annulus fluid to leak into the injection tube rather than 

allowing injectate to enter the annulus). The same extreme level of sensitivity 

obviously isn't warranted in the context of CO2 injection; as a result, the 

additional operating and maintenance costs typically needed to maintain an overpressurized annulus would not be justified. 

A pressurized annulus would permit detection of casing leaks whether or not 

annulus pressure exceeds injection pressure. Similarly, any significant pressure 

differential between in annulus and injection pressure would permit prompt 

detection of a tubing leak whether or not annulus pressure exceeds injection 

pressure. Accordingly, a requirement for a pressurized annulus is sufficient to 

protect USDWs without any requirement that annulus pressure exceed injection 

pressure. Indeed, a requirement that annulus pressure exceed injection pressure 

could - depending on the site conditions involved - do more to limit than 

enhance the sensitivity of leak detection. Consequently, the determination of 

annulus pressure should be left to the permitting process, without any 

presumption in favor of an over-pressurized annulus. 

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. EPA also believes this requirement is appropriate for Class VI wells given the potential

high volumes and supercritical nature of the CO2 injectate, potential geomechanical stresses in the

wellbore, and the potential for movement of the CO2 in the event of a mechanical integrity loss.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24468

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(b) 

Proposed CCS Group Recommendations: (b) Injection OF THE CO2 STREAM between the 

outermost casing protecting USDWs and the well bore is prohibited. 

Basis for CCS Group Comments: Routine injection into zones other than the target 

interval(s) should be prohibited, however, wording of this requirement is not 

clear as to which interval is being addressed. An absolute prohibition on 

injection into this annulus may also limit diagnostic or remedial options that 

could be useful. 

Response: EPA retains the provision as proposed, and clarifies that injection between the casing and

the well bore is prohibited. This is consistent with requirements for other injection well classes.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24469

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(c) 

Proposed CCS Group Recommendations: (c) The owner or operator must fill the 

annulus between the tubing and the long string casing with a non-corrosive fluid 

approved by the Director. The owner or operator must maintain a positive 

pressure on the annulus. 

Basis for CCS Group Comments: Industry experience with the Class II UIC program 

does not support this requirement as proposed by EPA. 

Positive annular pressure that exceeds the operating injection pressure is not 

necessary because a leak from tubing to annulus does not have the same 

implications as in a Class I hazardous situation. 

Response: EPA believes that maintaining an annulus pressure that is higher than the injection

pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the annulus fluid

will move into the tubing, rather than the injectate moving out of the tubing and potentially along the

outside of the well. EPA believes this requirement is appropriate for Class VI wells given the

potential high volumes and supercritical nature of the CO2 injectate, potential geomechanical

stresses in the wellbore, and the potential for movement of the CO2 in the event of a mechanical
integrity loss.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24470

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(d) 

Proposed CCS Group Recommendations: Support the proposed language.. 

Basis for CCS Group Comments: Agree with EPA’s rationale 

Response: EPA agrees that maintaining mechanical integrity is an essential component of protecting

USDWs. The final rule retains this provision.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24693

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(b) 

Anadarko Petroleum Corporation (APC) Comments: (b) Injection OF THE CO2 STREAM 

between the outermost casing protecting USDWs and the well bore is prohibited. 

Rationale: Routine injection into zones other than the target interval(s) should 

be prohibited, however, wording of this requirement is not clear as to which 

interval is being addressed. An absolute prohibition on injection into this 

annulus may also limit diagnostic options that could be useful. 

Response: EPA retains the provision as proposed, and clarifies that injection between the casing and

the well bore is prohibited. This is consistent with requirements for other injection well classes.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24694

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(c) 

Anadarko Petroleum Corporation (APC) Comments: (c) The owner or operator must 

fill the annulus between the tubing and the long string casing with a noncorrosive fluid approved by the Director. The owner or operator must maintain 

on the annulus a pressure that exceeds the operating injection pressure, 

unless the Director determines that such requirement might harm the integrity of 

the well. A POSITIVE PRESSURE ON THE ANNULUS. 

Rationale: Industry experience with the Class II UIC program does not support 

this requirement. 
Positive annular pressure that exceeds the operating injection pressure is not 

necessary because a leak from tubing to annulus does not have the same 

implications as in a Class I hazardous situation. 

Response: EPA believes that maintaining an annulus pressure that is higher than the injection

pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the annulus fluid

will move into the tubing, rather than the injectate moving out of the tubing and potentially along the

outside of the well. EPA believes this requirement is appropriate for Class VI wells given the

potential high volumes and supercritical nature of the CO2 injectate, potential geomechanical

stresses in the wellbore, and the potential for movement of the CO2 in the event of a mechanical

integrity loss.

Commenter Name: Ronald Evans Letter ID: 0215

Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24303

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: E. § 146.88 Injection well operating requirements. 

1. EPA Proposed §146.88(c) The owner or operator must fill the annulus 

between the tubing and the long string casing with a non-corrosive fluid 

approved by the Director. The owner or operator must maintain on the 

annulus a pressure that exceeds the operating injection pressure, unless 

the Director determines that such requirement might harm the integrity 

of the well. 

EPA’s suggested Mechanical Integrity ("MI") rule to maintain pressure on the 

annulus exceeding the operating injection pressure will, in most cases, result 

in an exceedance of the burst pressure of the casing. If the operator is 

required to maintain pressure on the annulus at a rate that is greater than the 

injection pressure (as indicated in EPA proposed §146.88(c)), monitoring the 

annulus pressure may not be an accurate indicator of mechanical integrity. The 

EPA appears to recognize this likelihood and thus allows the Director to waive 

the requirement. However, the rule should not require a questionable practice 

and then permit its waiver. Rather, the practice should only be required if the 

Director makes a determination that the conduct of the test will NOT cause a 

problem. The suggested revision is encapsulated below: 

(c) The owner or operator must fill the annulus between the tubing and 

the long string casing with a non-corrosive fluid approved by the 

Director. IF THE DIRECTOR DETERMINES THAT SUCH REQUIREMENT WILL NOT HARM 

THE INTEGRITY OF THE WELL, Tthe owner or operator must maintain A 

POSITIVE PRESSURE on the annulus a pressure that exceeds the 

operating injection pressure. ., unless the Director determines that 

such requirement might harm the integrity of the well.

Response: EPA disagrees that maintaining annulus pressures that exceed the injection pressure

would cause bursting of the casing. A properly designed well that takes into account the geologic and

geomechanical properties of the site based on information collected under §146.82 and meets the

construction requirements at §146.86 would be able to maintain integrity if the annulus pressure
were reasonably higher than injection pressure.

The purpose of continuous pressure monitoring (to demonstrate internal MI) is to demonstrate that

no pressure changes are occurring, because a drop in pressure on the annulus provides an early

indication that attention is needed to prevent a loss of MI or unacceptable fluid movement. EPA

believes that any change in the pressure on the annulus between tubing and long stem casing,

regardless of what the annulus pressure is relative to injection pressure, can indicate a leak. 

The GS rule, at §146.88(c), allows the Director to make exceptions if the Director determines that

such a requirement might harm the integrity of the well. The final regulation at §146.88(c) requires

that the owner or operator must maintain on the annulus a pressure that exceeds the operating

injection pressure, unless the Director determines that such requirement might harm the integrity of

the well or endanger a USDW.

Commenter Name: Darrick Eugene Letter ID: 0223

Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23983

Comment: 6. § 146.88 Injection well operating requirements. 

EPA Proposed §146.88(c) The owner or operator must fill the annulus 

between the tubing and the long string casing with a non-corrosive fluid 

approved by the Director. The owner or operator must maintain on the 

annulus a pressure that exceeds the operating injection pressure, unless 

the Director determines that such requirement might harm the integrity 

of the well. 

EPA’s suggested Mechanical Integrity ("MI") rule to maintain pressure on the 

annulus exceeding the operating injection pressure will, in most cases, result 

in an exceedance of the burst pressure of the casing. If the operator is 

required to maintain pressure on the annulus at a rate that is greater than the 

injection pressure (as indicated in EPA proposed §146.88(c)), monitoring the 

annulus pressure may not be an accurate indicator of mechanical integrity. The 

EPA appears to recognize this likelihood and thus allows the Director to waive 

the requirement. However, the rule should not require a questionable practice 

and then permit its waiver. Rather, the practice should only be required if the 

Director makes a determination that the conduct of the test will NOT cause a 

problem. The suggested revision is encapsulated below: 

Response: EPA disagrees that maintaining annulus pressures that exceed the injection pressure

would cause bursting of the casing. A properly designed well that takes into account the geologic and

geomechanical properties of the site based on information collected under §146.82 and meets the

construction requirements at §146.86 would be able to maintain integrity if the annulus pressure

were reasonably higher than injection pressure.

The purpose of continuous pressure monitoring (to demonstrate internal MI) is to demonstrate that

no pressure changes are occurring, because a drop in pressure on the annulus provides an early

indication that attention is needed to prevent a loss of MI or unacceptable fluid movement. EPA

believes that any change in the pressure on the annulus between tubing and long stem casing,

regardless of what the annulus pressure is relative to injection pressure, can indicate a leak. 
The GS rule, at §146.88(c), allows the Director to make exceptions if the Director determines that

such a requirement might harm the integrity of the well. The final regulation at §146.88(c) requires

that the owner or operator must maintain on the annulus a pressure that exceeds the operating

injection pressure, unless the Director determines that such requirement might harm the integrity of

the well or endanger a USDW.

Commenter Name: Darrick Eugene Letter ID: 0223

Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23984

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: problem. The suggested revision is encapsulated below: 

(c) The owner or operator must fill the annulus between the tubing and 

the long string casing with a non-corrosive fluid approved by the 

Director. IF THE DIRECTOR DETERMINES THAT SUCH REQUIREMENT WILL NOT HARM 

THE INTEGRITY OF THE WELL, Tthe owner or operator must maintain A 

POSITIVE PRESSURE on the annulus a pressure that exceeds the 

operating injection pressure. ., unless the Director determines that 

such requirement might harm the integrity of the well.

Response: As described above, EPA disagrees that maintaining annulus pressures that exceed the

injection pressure would cause bursting of the casing. Therefore, EPA disagrees with the suggested

revision.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23297

Comment: 146.88(c) Pressure on the annulus is not necessary in all situations. 

Maintaining pressure above the injection pressure will subject the long-string 

casing to unnecessary stress and is not commensurate with the risk associated 

with carbon dioxide injection. 

Response: EPA believes that maintaining an annulus pressure that is higher than the injection

pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the annulus fluid

will move into the tubing, rather than the injectate moving out of the tubing and potentially along the

outside of the well. EPA believes this requirement is appropriate for Class VI wells given the

potential high volumes and supercritical nature of the CO2 injectate, potential geomechanical

stresses in the wellbore, and the potential for movement of the CO2 in the event of a mechanical

integrity loss.

EPA does not believe that maintaining annulus pressures that exceed the injection pressure would

cause unacceptable stress on the casing. A properly designed well that takes into account the

geologic and geomechanical properties of the site based on information collected under §146.82 and

meets the construction requirements at §146.86 would be able to maintain integrity if the annulus

pressure were reasonably higher than injection pressure.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23298

Comment: 146.88(e) Is continuous recording of annular fluid volume possible or practical? 
Response: EPA believes that knowing annulus fluid volume, as required at §146.88(e), is a

necessary component of monitoring well mechanical integrity, but believes that monitoring the

annulus fluid volume added is sufficient to meet the intent of continuous monitoring of the pressure

on the annulus. The final GS rule at §146.90 (b)) requires that owners or operators use continuous

recording devices to monitor injection pressure, rate and volume; the pressure on the annulus

between the tubing and the long string casing; and the annulus fluid volume added.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24910

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: EPA Proposal: (b) Injection between the outer-most casing protecting USDWs and 

the well bore is prohibited. 

GWPC Recommendations: (b) Injection of the CO2 stream between the outermost 

casing protecting USDWs and the well bore is prohibited. 

Rationale: Routine injection into zones other than the target interval(s) should 

be prohibited, however, wording of this requirement is not clear as to which 

interval is being addressed. An absolute prohibition on injection may also 

limit diagnostic options that could be useful. 

Sometimes inject other things to remediate well. 

Response: EPA retains the provision as proposed, and clarifies that injection between the casing and

the well bore is prohibited. This is consistent with requirements for other injection well classes.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24911

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: EPA Proposal: (c) The owner or operator must fill the annulus between the tubing 

and the long string casing with a non-corrosive fluid approved by the Director. 

The owner or operator must maintain on the annulus a pressure that exceeds the 

operating injection pressure, unless the Director determines that such 

requirement might harm the integrity of the well. 

GWPC Recommendations: (c) The owner or operator must fill the annulus between 

the tubing and the long string casing with a corrosion inhibiting fluid approved 

by the Director. The owner or operator must maintain a positive pressure on the 

annulus. 

Rationale: Agency and Industry experience with the Class II UIC program does not 

support this requirement. The standard proposed by EPA is consistent with 

neither the risk level related to CO2 nor the specifications needed to monitor 

the annular space for leakage. 
Rule Provision: 146.88(d) 

EPA Proposal: (d) Other than during periods of well workover (maintenance) 

approved by the Director in which the sealed tubing-casing annulus is of 

necessity disassembled for maintenance or corrective procedures, the owner or 

operator must maintain mechanical integrity of the injection well at all times. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Response: EPA believes that maintaining an annulus pressure that is higher than the injection

pressure, as required at §146.88(c), is appropriate and will ensure that if there are leaks in the tubing,

the annulus fluid will move into the tubing, rather than the injectate moving out of the tubing and

potentially along the outside of the well. EPA believes this requirement is appropriate for Class VI

wells given the potential high volumes and supercritical nature of the CO2 injectate, potential

geomechanical stresses in the wellbore, and the potential for movement of the CO2 in the event of a

mechanical integrity loss.

EPA disagrees that maintaining an annulus pressure higher than the injection pressure impacts

continuous pressure monitoring for internal MI. The purpose of continuous pressure monitoring (to

demonstrate internal MI) is to demonstrate that no pressure changes are occurring, because a drop in

pressure on the annulus provides an early indication that attention is needed to prevent a loss of MI

or unacceptable fluid movement. EPA believes that any change in the pressure on the annulus

between tubing and long stem casing, regardless of what the annulus pressure is relative to injection

pressure, can indicate a leak.

EPA agrees with the commenter that maintaining mechanical integrity is an essential component of

protecting USDWs. The final rule retains a requirement to maintain mechanical integrity at

§146.88(d).

Comment Code: 4110 2.4.1.1 Injection pressure limitations 

Individual Comments

Commenter Name: Michael H. Cochran Letter ID:

0108

Commenter Organization: Bureau of Water, Division of Environment, Kansas

Department of Health & Environment (KDHE)

Comment

ID: 21976

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

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

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

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

not allow much of a safety factor in many cases. 

Response: EPA disagrees with the suggestion that injection pressure be set at 75 percent of fracture

pressure. EPA believes that this limitation may not allow for sufficient volumes of CO2 to be
transmitted away from the well and into the injection formation. EPA acknowledges that there may

be circumstances where a lower pressure limitation may be appropriate; in such cases, the Director

has the authority, at §146.88, to set a lower pressure limit in the operating permit.

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

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

injection zone must not exceed 90 percent of the fracture pressure of the injection zone, as specified

at §146.88(a). The fracture pressure (and, therefore, the injection pressure) are based on site-specific

geologic and geomechanical data collected during the site characterization process required at

§146.82. Tests are available and have been used by injection well operators, e.g., Class I operators,

to measure fracture pressure. Examples include the step-rate test, in-situ stress tests, and a

combination of a long spaced sonic log with laboratory measurement of the mechanical properties of

cores.

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24790

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: (a) Except during stimulation, the owner or operator must ensure that injection 

pressure does not exceed 90% of the fracture pressure of the injection zone so 

as to assure that the injection does not initiate new fractures or propagate 

existing fractures in the injection zone. In no case may injection pressure 

initiate fractures in the confining zone(s) or cause the movement of 

injection or formation fluids that endangers a USDW. 

Response: EPA disagrees with the suggested edit. The rule affords the Director discretion to require

more than one confining zone, as specified at §146.83(a)(2). Where more than one confining zone is

required, EPA believes that each confining zone provides a layer of protection for USDWs and

should remain intact. See the preamble discussion geologic siting requirements for additional

information.

Commenter Name: Dawn A. Thorne Letter ID:

0134

Commenter Organization: University of Utah Energy and Geoscience Institute on

behalf of the Southwest Regional Partnership

Comment

ID: 21658

Comment: - Section 146.88(a) "Except during stimulation, the owner or operator must 

ensure that injection pressure does not exceed 90 percent of the fracture 

pressure of the injection zone so as to assure that the injection does not 

initiate new fractures or propagate existing fractures in the injection zone(s) 

or cause the movement of injection or formation fluids that endangers a USDW." 

Response/Discussion: It should be noted that for GS, injection pressure must be 

maximized. As the pressure spreads, the state of stress away from the well will 

also change. It must also be considered that unmapped faults could exist at some 

distance away from the injection well. The pressure needed to reactivate or 

propagate these faults could be less than 90 percent of the fracture pressure. 

The SWP would like to recommend a site-specific, performance-based approach to 

injection pressure requirements. Continuous site monitoring (discussed in 

Sections 146.88(e) and 146.90(g)) along with a detailed mitigation plan, will 

help operators and the EPA Director develop site-specific injection pressure and 
mitigation plan requirements. 

Response: EPA agrees that the maximum injection pressure should be based on site-specific

conditions. During the site characterization process, owners or operators must submit data about the

geology of the site, as specified at §146.82(a), including data on known or suspected faults and

fractures and geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid

pressures within the confining zone. If the Director determines, based on a review of this

information, that a lower injection pressure limitation is appropriate, the Director has the authority to

set a lower limit in the operating permit. EPA adds that any sites with the potential for reopening or

reactivation of faults or unacceptable seismic risk that could otherwise interfere with containment

will not be permitted as GS sites.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141

Commenter Organization: Global Energy, Inc. Comment ID: 23117

Comment: 3.Injection pressure limitations, controlled by instrumentation, and monitored 

and recorded, are appropriate. We support the reasonableness of the suggested 90 

percent criteria as a pressure limitation. We also counsel reasonableness with 

respect to selecting what that pressure is. 

Response: EPA agrees that the injection pressure should not exceed 90 percent of the fracture

pressure of the injection zone. The final rule retains this provision at §146.88(a). EPA believes that

the 90 percent requirement, which was suggested by IOGCC and permit writers whom EPA

consulted when writing the regulation, is a satisfactory margin of safety for well operation necessary

to protect USDWs from endangerment.

Commenter Name: Bonnie Lovelace Letter ID: 0152

Commenter Organization: Montana Department of Environmental Quality

(MDEQ)

Comment ID:

22131

Comment: 146.88(a) : MDEQ believes that the factor of safety is too low with 90 percent 

of the fracture pressure allowed. A safer level ofabout 75 percent should be 

required. 

Response: EPA disagrees with the suggestion that injection pressure be set at 75 percent of fracture

pressure. EPA believes that this limitation may not allow for sufficient volumes of CO2 to be

transmitted away from the well and into the injection formation. EPA acknowledges that there may

be circumstances where a lower pressure limitation may be appropriate; in such cases, the Director

has the authority set a lower pressure limit in the operating permit.

Commenter Name: James Dooley Letter ID: 0156

Commenter Organization: Joint Global Change Research Institute, Pacific

Northwest National Laboratory

Comment ID:

22639

Comment: 90% of the Injection Zone or the Caprock’s Fracture Pressure Page 43510 under 

"Proposed Injection Well Operating Requirements." Citing the IOGCC report and 

the expert opinion of permit writers is not the most rigorous basis for 

asserting that injection pressure can not exceed 90% of fracture pressure for 

all GS applications. Perhaps in a Notice of Data Availability (NODA) for this 

rule, USEPA could ask for data or studies that would help establish a firmer 

basis for this threshold. This is an important criteria as it directly impacts 
how much CO2 can be put down a given well and therefore how many wells will be 

needed to handle the anthropogenic CO2 from a given facility. The number of 

injector wells is a key determinant of the cost of CO2 storage. On page 43538, 

this same language is found in the proposed rule text (i.e., not in the 

preamble). 

Response: EPA believes that the injection pressure limits in the final GS rule are appropriate and

necessary to protects USDWs from endangerment. The injection pressure limit for each GS project

will be based on site-specific conditions, and be informed by data on the injection zone. During

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

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

pressure) are based on site-specific geologic and geomechanical data collected during the site

characterization process required at §146.82. Tests are available and have been used by injection

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

test, in-situ stress tests, and a combination of a long spaced sonic log with laboratory measurement

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

set the injection pressure limit at 90 percent of this value. 

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

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

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

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

prohibited at §146.88(a).

EPA published a Notice of Data Availability and Request for Comment on August 31, 2009 (74 FR

44802) that described research underway at several pilot projects and LBNL and sought comment on

any other research associated with potential environmental risks and risk management approaches for

GS. EPA received a variety of comments and data in response, but none of the comments or

information provided by commenters provided scientific rationale to support changing the injection

pressure limitation.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24180

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(a) 

API Comments: (a) Except during stimulation, the owner or operator must ensure 

that injection pressure does not exceed 90 percent of the fracture pressure of 

the injection zone so as to assure that the injection does not initiate new 

fractures or propagate existing fractures in the injection zone. In no case may 

injection pressure initiate fractures in the confining zone(s) or cause the 

movement of injection or formation fluids that endangers a USDW. (A) THE OWNER 

OR OPERATOR MUST COMPLY WITH A MAXIMUM INJECTION PRESSURE LIMIT

APPROVED BY THE 

DIRECTOR AND SPECIFIED IN THE PERMIT. IN APPROVING A MAXIMUM INJECTION

PRESSURE 

LIMIT, THE DIRECTOR SHALL CONSIDER THE RESULTS OF WELL TESTS AND, WHERE 

APPROPRIATE, GEOMECHANICAL OR OTHER STUDIES THAT ASSESS THE RISKS OF
TENSILE 

FAILURE AND SHEAR FAILURE. THE DIRECTOR SHALL APPROVE LIMITS THAT, WITH

A 

REASONABLE DEGREE OF CERTAINTY, WILL AVOID INITIATION OR PROPAGATION

OF 

FRACTURES IN THE CONFINING ZONE OR CAUSE OTHERWISE NON-TRANSMISSIVE

FAULTS 

TRANSECTING THE CONFINING ZONE TO BECOME TRANSMISSIVE. IN NO CASE MAY

INJECTION 

PRESSURE CAUSE MOVEMENT OF INJECTION OR FORMATION FLUIDS IN A MANNER

PROHIBITED 

BY 40 CFR PART 144.12(A) 

Rationale: API is concerned about three aspects of proposed section 146.88(a), 

governing injection pressure limitations. First, it "restricts" fractures in the 

injection zone "except during stimulation" rather than focusing on maintaining 

the integrity of the confining zone, which is what really matters for protecting 

USDWs. Second, it fails to refer specifically to the full range of potential 

geomechanical failure modes potentially posed by operations at a particular 

site. Third, the type of geomechanical risk that is addressed (initiation or 

propagation of fractures), is dealt with in a potentially arbitrary fashion (the 

90% of fracture pressure limit), which may not be appropriate in all cases. 

The MSDG‘s recommended language addresses these concerns by focusing on 

maintaining the integrity of the confining zone and including tensile failure 

and shear failure as transmissivity concerns. It calls for additional 

geomechanical studies of tensile failure and shear failure only "where 

appropriate" because there will be locations where experience or existing 

information will provide sufficient evidence to avoid the need for additional 

studies. The need for conducting additional tests and for determining which 

tests would be acceptable is left to the Director‘s discretion. 

Response: EPA notes that because determination of the injection pressure limit is based on the

fracture pressure of the injection zone, the limit is site-specific and not arbitrary. EPA emphasizes

that injection pressure limits are important to protect against fracturing of the confining zone, and

that the requirement at §146.88(a) that the pressure in the injection zone not exceed 90 percent of the

fracture pressure provides a margin of safety in the well operation and protects USDWs from

endangerment. If the Director determines, based on a review of the information collected as part of

site characterization, that a lower injection pressure limitation is appropriate in order to prevent

endangerment of USDWs, the Director has the authority to set a lower limit in the operating permit

than the limit established in the rule. 

EPA notes that during the site characterization process, owners or operators must submit data about

the geology of the site, as specified at §146.82(a), including data on known or suspected faults and

fractures and geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid

pressures within the confining zone. The Director will use these data to determine appropriate limits

on injection. 

In response to the concern about reopening of faults at lower pressures than 90 percent of fracture

pressure, EPA believes that the requirement for the owner or operator to submit data on known or
suspected faults and fractures and information on the seismic history of the site will inform the

determination of an appropriate pressure limitation in the permit. Any sites with the potential for

reopening or reactivation of faults or unacceptable seismic risk that could otherwise interfere with

containment will not be permitted as GS sites.

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: Robert J. Finley Letter ID: 0180

Commenter Organization: Illinois State Geological Survey Comment ID: 23618

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. 

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.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23739

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Part 146.88(a) AWWA is concerned that the limitation on injection pressure to 
90% of the fracture pressure is not stringent enough. We heard it stated at the 

public hearing in Denver that fracturing of the injection formation can occur 

when injection pressures are below 90% of the fracture pressure. It is important 

to consider that injection pressure limitations need to take account of the 

possibility that, under certain conditions, faults can be re-activated even if 

injection pressures are kept below the level necessary to create new fractures 

or propagate existing fractures. Therefore, the regulation should provide for 

the injection pressure to be calculated based on the site geology, hydrogeology 

and geomechanics, in combination with the injection pressure limitation. 

Injection pressures and rates should be determined by well tests and 

geomechancial studies, taking into account both formation fracture pressure and 

formation parting pressure. However, due to the amount of uncertainty associated 

with this topic, AWWA recommends that EPA research their proposed limitation in 

more detail to determine the best method for preventing possible contamination 

of USDWs. Therefore, we recommend revising this part to read: 

The owner or operator must ensure that injection pressure and rates remain 

within limits established by permit. Such permit limitations shall be based on 

well tests and geomechanical studies, including assessments of both the fracture 

pressure of the confining zone and the parting pressure of the confining zone. 

In no case may injection pressure initiate or propagate fractures in the 

confining zone, cause otherwise non-transmissive faults transecting the 

confining zone to become transmissible, otherwise degrade the integrity of the 

confining zone, or cause the movement of injection or formation fluids that 

endangers a USDW. 

Response: EPA agrees that the operator must remain within limits established by the Class VI

permit. EPA clarifies that the owner or operator is required in §146.82(a)(7) to propose a maximum

injection pressure as part of the permit application. The proposed injection pressure will be evaluated

by the Director based on site-specific conditions, and be informed by data on the injection zone.

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

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

injection pressure) are based on site-specific geologic and geomechanical data collected during the

site characterization process required at §146.82. If, based on this information, a lower pressure

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

In response to the concern about reopening of faults at lower pressures than 90 percent of fracture

pressure, EPA believes that the requirement for the owner or operator to submit data on known or

suspected faults and fractures and information on the seismic history of the site will inform the

determination of an appropriate pressure limitation in the permit. Any sites with the potential for

reopening or reactivation of faults or unacceptable seismic risk that could otherwise interfere with

containment will not be permitted as GS sites.

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

primacy agencies that will include recommended approaches for evaluating owner or operatorsubmitted data in setting permit conditions. The guidance will be available on EPA's web site, at
http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25191

Comment: provided there is no endangerment to USDWs. In addition, NYSDEC-DMN agrees with 

EPA’s position that an injection pressure safety factor be included in that the 

maximum allowable injection pressure during operational injection be limited to 

90 percent of the fracture pressure of the injection zone. 

Response: EPA agrees that the injection pressure should not exceed 90 percent of the fracture

pressure of the injection zone. The final rule retains this provision at §146.88(a). EPA believes that

the 90 percent requirement, which was suggested by State representatives whom EPA consulted

when writing the regulation, is a satisfactory margin of safety during well operation necessary to

protect USDWs from endangerment.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24344

Comment: E. Injection Well Operating Requirements 

1. Injection Pressure Limitations 

We support the discussion and recommendation on injection pressure limitations 

presented in the Joint Letter resulting from the multi-stakeholder discussion. 

Response: EPA notes that because determination of the injection pressure limit is based on the

fracture pressure of the injection zone, the limit is site-specific and not arbitrary. EPA emphasizes

that injection pressure limits are important to protect against fracturing of the confining zone, and

that the requirement at §146.88(a) that the pressure in the injection zone not exceed 90 percent of the

fracture pressure provides a margin of safety in the well operation and protects USDWs from

endangerment. If the Director determines, based on a review of the information collected as part of

site characterization, that a lower injection pressure limitation is appropriate, the Director has the

authority to set a lower limit in the operating permit than the limit established in the rule.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24467

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(a) 

Proposed CCS Group Recommendations: (a) Except during stimulation, the owner 

or operator must ensure that injection pressure does not exceed 90 percent of 

the fracture pressure of the injection zone so as to assure that the injection 

does not initiate new fractures or propagate existing fractures in the injection 

zone. In no case may injection pressure initiate fractures in the confining 

zone(s) or cause the movement of injection or formation fluids that endangers a 

USDW. THE OWNER OR OPERATOR MUST COMPLY WITH A MAXIMUM INJECTION

PRESSURE 
LIMIT APPROVED BY THE DIRECTOR AND SPECIFIED IN THE PERMIT. IN APPROVING

A 

MAXIMUM INJECTION PRESSURE LIMIT, THE DIRECTOR SHALL CONSIDER THE

RESULTS OF 

WELL TESTS AND, WHERE APPROPRIATE, GEOMECHANICAL OR OTHER STUDIES

THAT ASSESS 

THE RISKS OF TENSILE FAILURE AND SHEAR FAILURE. THE DIRECTOR SHALL

APPROVE 

LIMITS THAT, WITH A REASONABLE DEGREE OF CERTAINTY, WILL AVOID

INITIATION OR 

PROPAGATION OF FRACTURES IN THE CONFINING ZONE OR CAUSE OTHERWISE

NONTRANSMISSIVE FAULTS TRANSECTING THE CONFINING ZONE TO BECOME

TRANSMISSIVE. IN NO 

CASE MAY INJECTION PRESSURE CAUSE MOVEMENT OF INJECTION OR FORMATION

FLUIDS IN A 

MANNER PROHIBITED BY 40 CFR PART 144.12(A). 

Basis for CCS Group Comments: We are concerned about three aspects of proposed 

section 146.88(a), governing injection pressure limitations. First, it 

"restricts" fractures in the injection zone "except during stimulation" rather 

than focusing on maintaining the integrity of the confining zone, which is what 

really matters for protecting USDWs. Second, it fails to refer specifically to 

the full range of potential geomechanical failure modes potentially posed by 

operations at a particular site. Third, the type of geomechanical risk that is 

addressed (initiation or propagation of fractures), is dealt with in a 

potentially arbitrary fashion (the 90% of fracture pressure limit), which may 

not be appropriate in all cases. 

Our recommended language addresses these concerns by focusing on maintaining the 

integrity of the confining zone and including tensile failure and shear failure 

as transmissivity concerns. It calls for additional geomechanical studies of 

tensile failure and shear failure only "where appropriate" because there will be 

ocations where experience or existing information will provide sufficient 

evidence to avoid the need for additional studies. The need for conducting 

additional tests and for determining which tests would be acceptable is left to 

the Director’s discretion. 

This is the same recommendation as presented by the multi-stakeholder group, in 

which the Carbon Sequestration Council participated. 

Response: EPA notes that because determination of the injection pressure limit is based on the

fracture pressure of the injection zone, the limit is site-specific and not arbitrary. EPA emphasizes

that injection pressure limits are important to protect against fracturing of the confining zone, and

that the requirement at §146.88(a) that the pressure in the injection zone not exceed 90 percent of the

fracture pressure provides a margin of safety in the well operation and protects USDWs from

endangerment. If the Director determines, based on a review of the information collected as part of

site characterization, that a lower injection pressure limitation is appropriate in order to prevent

endangerment of USDWs, the Director has the authority to set a lower limit in the operating permit

than the limit established in the rule. 
EPA notes that during the site characterization process, owners or operators must submit data about

the geology of the site, as specified at §146.82(a), including data on known or suspected faults and

fractures and geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid

pressures within the confining zone. The Director will use these data to determine appropriate limits

on injection. 

In response to the concern about reopening of faults at lower pressures than 90 percent of fracture

pressure, EPA believes that the requirement for the owner or operator to submit data on known or

suspected faults and fractures and information on the seismic history of the site will inform the

determination of an appropriate pressure limitation in the permit. Any sites with the potential for

reopening or reactivation of faults or unacceptable seismic risk that could otherwise interfere with

containment will not be permitted as GS sites.

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: Kyle Isakower Letter ID: 0191

Commenter Organization: American Petroleum Institute Comment ID: 23879

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Injection Pressure Limitations 

We are concerned about three aspects of proposed section 146.88(a), governing 

injection pressure limitations. First, it "restricts" fractures in the injection 

zone "except during stimulation" rather than focusing on maintaining the 

integrity of the confining zone, which is what really matters for protecting 

USDWs. Second, it fails to refer specifically to the full range of potential 

geomechanical failure modes potentially posed by operations at a particular 

site. Third, the type of geomechanical risk that is addressed (initiation or 

propagation of fractures), is dealt with in a potentially arbitrary fashion (the 

90% of fracture pressure limit), which may not be appropriate in all cases. 

Our recommended language addresses these concerns by focusing on maintaining the 

integrity of the confining zone and including tensile failure and shear failure 

as transmissivity concerns. It calls for additional geomechanical studies of 

tensile failure and shear failure only "where appropriate" because there will be 

locations where experience or existing information will provide sufficient 

evidence to avoid the need for additional studies. The need for conducting 

additional tests and for determining which tests would be acceptable is left to 

the Director’s discretion. 

The owner or operator must comply with a maximum injection pressure 
limit approved by the Director and specified in the permit. In approving 

a maximum injection pressure limit, the Director shall consider the 

results of well tests and, where appropriate, geomechanical or other 

studies that assess the risks of tensile failure and shear failure. The 

Director shall approve limits that, with a reasonable degree of 

certainty, will avoid initiation or propagation of fractures in the 

confining zone or cause otherwise non-transmissive faults transecting 

the confining zone to become transmissive. In no case may injection 

pressure cause movement of injection or formation fluids in a manner 

prohibited by 40 CFR Part 144.12(a). 

Response: EPA notes that because determination of the injection pressure limit is based on the

fracture pressure of the injection zone, the limit is site-specific and not arbitrary and is appropriate to

protect USDWs from endangerment. EPA emphasizes that injection pressure limits are important to

protect against fracturing of the confining zone, and that the requirement at §146.88(a) that the

pressure in the injection zone not exceed 90 percent of the fracture pressure provides a margin of

safety in the well operation and protects USDWs from endangerment. If the Director determines,

based on a review of the information collected as part of site characterization, that a lower injection

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

permit than the limit established in the rule. 

EPA notes that during the site characterization process, owners or operators must submit data about

the geology of the site, as specified at §146.82(a), including data on known or suspected faults and

fractures and geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid

pressures within the confining zone. The Director will use these data to determine appropriate limits

on injection. 

In response to the concern about reopening of faults at lower pressures than 90 percent of fracture

pressure, EPA believes that the requirement for the owner or operator to submit data on known or

suspected faults and fractures and information on the seismic history of the site will inform the

determination of an appropriate pressure limitation in the permit. Any sites with the potential for

reopening or reactivation of faults or unacceptable seismic risk that could otherwise interfere with

containment will not be permitted as GS sites. 

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: Jeff W. Sheets Letter ID: 0192

Commenter Organization: ConocoPhillips Comment ID: 23892

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Injection Pressure Limitations 
We are concerned about three aspects of proposed 146.88(a), governing injection 

pressure limitations. First, it "restricts" fractures in the injection zone 

"except during stimulation" rather than focusing on maintaining the integrity of 

the confining zone, which is the suggested focus for protecting USDWs. Second, 

it misses an opportunity to refer specifically to the full range of potential 

geomechanical failure modes potentially posed by operations at a particular 

site. Third, the type of geomechanical risk that is addressed (initiation or 

propagation of fractures), is dealt with in a potentially arbitrary fashion (the 

90% of fracture pressure limit), which may not be appropriate in all cases. 

The MSDG's recommended language addresses these concerns by focusing on 

maintaining the integrity of the confining zone and including tensile failure 

and shear failure as appropriate to evaluate for potential transmissivity 

concerns. It calls for additional geomechanical studies of tensile failure and 

shear failure only "where appropriate" because there will be locations where 

experience or existing information will provide sufficient evidence to avoid the 

need for additional studies. The need for conducting additional tests and for 

determining which tests would be acceptable is left to the Director's 

discretion. Recommended language: 

The owner or operator must comply with a maximum injection pressure 

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

a maximum injection pressure limit, the Director shall consider the 

results of well tests and, where appropriate, geomechanical or other 

studies that assess the risks of tensile failure and shear failure. The 

Director shall approve limits that, with a reasonable degree of 

certainty, will avoid initiation or propagation of fractures in the 

confining zone or cause otherwise non-transmissive faults transecting 

the confiding zone to become transmissive. In no case may injection 

pressure cause movement of injection or formation fluids in a manner 

prohibited by 40 CFR Part 144.12(a). 

Response: EPA notes that because determination of the injection pressure limit is based on the

fracture pressure of the injection zone, the limit is site-specific and not arbitrary. EPA emphasizes

that injection pressure limits are important to protect against fracturing of the confining zone, and

that the requirement at §146.88(a) that the pressure in the injection zone not exceed 90 percent of the

fracture pressure provides a margin of safety in the well operation and protects USDWs from

endangerment. If the Director determines, based on a review of the information collected as part of

site characterization, that a lower injection pressure limitation is appropriate, the Director has the

authority to set a lower limit in the operating permit than the limit established in the rule. 

EPA notes that during the site characterization process, owners or operators must submit data about

the geology of the site, as specified at §146.82(a), including data on known or suspected faults and

fractures and geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid

pressures within the confining zone. The Director will use these data to determine appropriate limits

on injection. 

In response to the concern about reopening of faults at lower pressures than 90 percent of fracture

pressure, EPA believes that the requirement for the owner or operator to submit data on known or

suspected faults and fractures and information on the seismic history of the site will inform the
determination of an appropriate pressure limitation in the permit. Any sites with the potential for

reopening or reactivation of faults or unacceptable seismic risk that could otherwise interfere with

containment will not be permitted as GS sites.

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24692

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(a) 

Anadarko Petroleum Corporation (APC) Comments: (a) Except during stimulation, 

the owner or operator must ensure that injection pressure does not exceed 90 

percent of the fracture pressure of the injection zone so as to assure that the 

injection does not initiate new fractures or propagate existing fractures in the 

injection zone. In no case may injection pressure initiate fractures in the 

confining zone(s) or cause the movement of injection or formation fluids that 

endangers a USDW.

(A) THE OWNER OR OPERATOR MUST COMPLY WITH A MAXIMUM INJECTION

PRESSURE LIMIT 

APPROVED BY THE DIRECTOR AND SPECIFIED IN THE PERMIT. IN APPROVING A

MAXIMUM 

INJECTION PRESSURE LIMIT, THE DIRECTOR SHALL CONSIDER THE RESULTS OF

WELL TESTS. 

THE DIRECTOR SHALL APPROVE LIMITS THAT, WITH A REASONABLE DEGREE OF

CERTAINTY, 

WILL AVOID INITIATION OR PROPAGATION OF FRACTURES IN THE CONFINING ZONE

OR CAUSE 

OTHERWISE NONTRANSMISSIVE FAULTS TRANSECTING THE CONFINING ZONE TO

BECOME 

TRANSMISSIVE. IN NO CASE MAY INJECTION PRESSURE CAUSE MOVEMENT OF

INJECTION OR 

FORMATION FLUIDS IN A MANNER PROHIBITED BY 40 CFR PART 144.12(A) 

Rationale: Maintaining the integrity of the confining zone is the critical 

parameter. 

Response: EPA notes that because determination of the injection pressure limit is based on the

fracture pressure of the injection zone, the limit is site-specific and not arbitrary. EPA emphasizes

that injection pressure limits are important to protect against fracturing of the confining zone, and
that the requirement at §146.88(a) that the pressure in the injection zone not exceed 90 percent of the

fracture pressure provides a margin of safety in the well operation and protects USDWs from

endangerment. If the Director determines, based on a review of the information collected as part of

site characterization, that a lower injection pressure limitation is appropriate, the Director has the

authority to set a lower limit in the operating permit than the limit established in the rule. 

EPA notes that during the site characterization process, owners or operators must submit data about

the geology of the site, as specified at §146.82(a), including data on known or suspected faults and

fractures and geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid

pressures within the confining zone. The Director will use these data to determine appropriate limits

on injection. 

In response to the concern about reopening of faults at lower pressures than 90 percent of fracture

pressure, EPA believes that the requirement for the owner or operator to submit data on known or

suspected faults and fractures and information on the seismic history of the site will inform the

determination of an appropriate pressure limitation in the permit. Any sites with the potential for

reopening or reactivation of faults or unacceptable seismic risk that could otherwise interfere with

containment will not be permitted as GS sites.

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: John King Letter ID: 0211

Commenter Organization: Shell Exploration and Production Company

(SEPCo)

Comment ID:

22772

Other EPA Comment Codes and Descriptions: 4120 2.4.1.2 Allowing hydraulic fracturing during

GS (seeking comment) 

Comment: D. Injection Well Operating Requirements 

1. Injection Pressure Limitations 

Under the existing UIC regulations, permits for Class II injection wells must 

limit injection pressure as follows: 

Injection pressure at the wellhead shall not exceed a maximum, which shall be 

calculated so as to assure that the pressure during injection does not initiate 

new fractures or propagate existing fractures in the confining zone adjacent to 

the USDWs. In no case shall injection pressure cause the movement of injection 

or formation fluids into an underground source of drinking water. 

40 C.F.R. 146.23(a)(1). This has proven to be an effective regulatory 

requirement that provides a flexible and appropriate performance standard to be 

applied on the basis of site-specific conditions. This regulatory approach has 
proved successful in the Class II context, and there is no basis to conclude 

that a similar standard would not be appropriate in the context of carbon 

sequestration. 

The Class I requirements impose more restrictive requirements designed not just 

to prevent endangerment of USDWs, but to ensure that there is no fracturing in 

the injection zone during normal operation. The latter requirement may make 

sense when "no migration" exemptions depend upon the integrity of confining or 

"arrestment" strata within the injection zone, but such a requirement is 

certainly more rigid than necessary to prevent endangerment of USDWs. 

Accordingly, such a standard is not necessary in the context of carbon 

sequestration, and would be ill-suited in a rule that must have the flexibility 

to address a wide range of potential injection scenarios. 

Recommendation: 

Injection pressure limitations for Class VI injection wells should be based on 

the existing Class II requirements, modified slightly to address the possibility 

of Class VI injection occurring above the lowermost USDW. We recommend the 

following specific language: 

Injection pressure at the wellhead shall not exceed a maximum, which shall be 

calculated so as to assure that the pressure during injection does not initiate 

new fractures or propagate existing fractures in the confining zone. In no case 

shall injection pressure cause movement of injection or formation fluids that 

endangers an underground source of drinking water. 

Response: EPA believes that the injection pressure limits in the GS rule are important to protect

against fracturing of the confining zone, and that the requirement at §146.88(a) that the pressure in

the injection zone not exceed 90 percent of the fracture pressure provides a margin of safety in the

well operation and protects USDWs from endangerment. 

The pressure limitations are tailored to the unique nature of CO2 injection for GS and afford

flexibility to address site-specific circumstances. EPA notes that during the site characterization

process, owners or operators must submit data about the geology of the site, as specified at

§146.82(a), including data on known or suspected faults and fractures and geomechanical

information on fractures, stress, ductility, rock strength, and in situ fluid pressures within the

confining zone. The Director will use these data to determine appropriate limits on injection. 

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. The Department of Energy is

developing a Best Practices Manual on site characterization.
Commenter Name: Saba Tahmassebi Letter ID: 0218

Commenter Organization: Oklahoma Department of Environmental Quality

(DEQ)

Comment ID:

21565

Comment: 4. Reexamine the standard for injection pressure. The proposed rule sets a limit 

on injection pressure that is less than 90 percent of the fracture pressure of 

the injection zones. EPA may be aware that injection zones may also include 

sealed or closed fractures that are not permeable. These fractures may re-open 

at pressures below the 90 percent requirement providing a conduit for fluid 

migration. Oklahoma DEQ recommends that EPA consider the effect on the sealed 

and closed fractures and modify the maximum pressure requirement accordingly. 

Response: EPA notes that during the site characterization process, owners or operators must submit

data about the geology of the site, as specified at §146.82(a), including data on known or suspected

faults and fractures and geomechanical information on fractures, stress, ductility, rock strength, and

in situ fluid pressures within the confining zone. The Director will use these data to determine

appropriate limits on injection. If the Director determines, based on a review of the information

collected as part of site characterization, that a lower injection pressure limitation is appropriate, the

Director has the authority to set a lower limit in the operating permit than the limit established in the

rule. 

In response to the concern about reopening of faults at lower pressures than 90 percent of fracture

pressure, EPA believes that the requirement for the owner or operator to submit data on known or

suspected faults and fractures and information on the seismic history of the site will inform the

determination of an appropriate pressure limitation in the permit. Any sites with the potential for

reopening or reactivation of faults or unacceptable seismic risk that could otherwise interfere with

containment will not be permitted as GS sites.

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: Andrew Duguid Letter ID: 0226

Commenter Organization: Schlumberger Carbon Services Comment ID: 24048

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: §146.88 Injection well operating requirements. 

Proposed Rule: (a) Except during stimulation, the owner or operator must ensure 

that injection pressure does not exceed 90 percent of the fracture pressure of 

the injection zone so as to assure that the injection does not initiate new 

fractures or propagate existing fractures in the injection zone. In no case may 

injection pressure initiate fractures in the confining zone(s) or cause the 

movement of injection or formation fluids that endangers a USDW. 
Schlumberger Suggested Revision: (a) Except during stimulation, the owner or 

operator must ensure that injection pressure does not exceed 90 percent of the 

hydraulic fracture pressure of the confining zone so as to assure that the 

injection does not initiate new fractures or propagate existing fractures in the 

confining zone. In no case may injection pressure initiate fractures in the 

confining zone(s) or cause the movement of injection or formation fluids that 

endangers a USDW. 

Schlumberger Rationale: Maintaining the integrity of the confining zone is the 

critical parameter. 

Response: EPA agrees that maintaining the integrity of the confining zone is critical in order to

protect USDWs from endangerment. However, EPA also believes that the injection pressure should

not exceed 90 percent of the fracture pressure of the injection zone. The final rule retains this

provision at §146.88(a). EPA believes that the 90 percent requirement, which was suggested by

IOGCC and permit writers whom EPA consulted when writing the regulation, is a satisfactory

margin of safety for well operation.

Commenter Name: Neeraj Gupta Letter ID: 0229

Commenter Organization: Battelle Energy Technology (BET) Comment ID: 21846

Comment: Page 84, Fracture Pressures- We would suggest using a defined equation rather 

than 90% fracture pressure for injection pressure limits. Michigan and Ohio 

sites have permitted using a general equation to determine maximum allowable 

surface injection pressure: 

Maximum Allowable Surface Injection Pressure = 

depth x [(FG - 0.433 x (S.G. + safety factor)] - 14.7 

Depth = depth at top of storage interval 

FG = fracture gradient 

S.G. (average specific gravity of CO2 in borehole) 

Safety factor = 0.05 

14.7 = general friction factor 

We have seen different fracture gradients: Region 5 EPA specifies 0.8 psi/ft, 

but Ohio specifies 0.75 psi/ft. They also permit determination of higher 

fracture pressures with field tests. Also, this equation allows 95% of fracture 

pressure. Why would CO2 require adjusting to 90% of fracture pressure? 

Response: EPA believes that injection pressures that are based on 90 percent of the fracture pressure

are an appropriate maximum for the federal requirements. However, the determination of the

injection pressure for a specific project must be approved by the Director. Additionally, the Agency

clarifies that if, in preparing any permit, if the Director determines, based on site-specific

information, that a lower injection pressure is appropriate to ensure protection of USDWs from

endangerment, he or she has the authority to set a lower injection pressure limit in the permit. The

Agency clarifies that if a permitting authority wants to use an equation to set the injection pressure

limit in a GS permit, this is acceptable. However, the safety factor must be based on 90 percent of
the fracture pressure in order to protect USDWs from endangerment.

Commenter Name: Steven B. Corneli Letter ID: 0234

Commenter Organization: NRG Energy, Inc. Comment ID: 23166

Comment: 1. Injection Pressure Limitations 

The proposed rule does not allow injection pressures that exceed 90% of the 

fracture pressure of the receiving formation. NRG believes that this rule of 

thumb would be an over protective requirement and would not be necessary for 

ensuring containment of CO2 in the receiving formation. The existing requirement 

under the UIC regulations for Class II wells allows injection pressure limits 

that are based on site-specific conditions (i.e., well tests and geomechanical 

studies) that have been proven to be effective in protecting the confining zone. 

We believe a standard similar to Class II injection wells would be appropriate 

for GS. 

Response: EPA believes the operating requirements for Class VI wells, including the pressure

limitation, are necessary to protect USDWs from endangerment by providing multiple safeguards to

ensure that well integrity, containment of fluids within the injection zone, and the integrity of the

confining zone. 

EPA emphasizes that injection pressure limits are important to protect against fracturing of the

confining zone, and that the requirement at §146.88(a) that the pressure in the injection zone not

exceed 90 percent of the fracture pressure provides a margin of safety in the well operation and

protects USDWs from endangerment. If the Director determines, based on a review of the

information collected as part of site characterization, that a lower injection pressure limitation is

appropriate, the Director has the authority to set a lower limit in the operating permit than the limit

established in the rule. 

EPA notes that the pressure limitation at §146.88(a) accounts for site-specific conditions. During the

site characterization process, owners or operators must submit data about the geology of the site, as

specified at §146.82(a), including data on known or suspected faults and fractures and

geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid pressures

within the confining zone. The Director will use these data to determine appropriate limits on

injection. 

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: Philip Papadeas Letter ID: 0238

Commenter Organization: Sandia Technologies, LLC Comment ID: 23354

Comment: §146.88 (a)(e) 
Re: Fracture Pressure 

Fracture pressure determination should be key to EPA’s rules, via geophysical 

measurements, physical rock cores sampling and determination, and openhole logs. 

There are sufficient tools and methods present to evaluate the Confining Zone 

and Injection interval fracture gradients and determine an appropriate operating 

range with safeguards present for operation pressure and injection rate. 

Response: EPA agrees it is important to accurately determine fracture pressure in setting permit

limits for Class VI wells. The injection pressure limit for each GS project will be based on sitespecific conditions and will be informed by data on the injection zone. During injection, the pressure

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

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

site-specific geologic and geomechanical data collected during the site characterization process

required at §146.82. Tests are available and have been used by injection well operators, e.g., Class I

operators, to measure fracture pressure. Examples include the step-rate test, in-situ stress tests, and a

combination of a long spaced sonic log with laboratory measurement of the mechanical properties of

cores. To meet the GS requirements, the permitting authority must set the injection pressure limit at

no more than 90 percent of this value. 

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

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

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

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

prohibited at §146.88(a).

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: Kurt Waltzer Letter ID: 0250

Commenter Organization: Clean Air Task Force Comment ID: 22289

Comment: Pressure limits 

We believe that the pressure management provisions in §146.88(a) require 

modification. The members of our Environmental NGO Group have not reached 

agreement on the exact language for the suggested changes and are either 

submitting individual comments on this issue or are submitting comments jointly 

with other groups. We do agree, however, that injection pressure limits must be 

established after adequately considering the risks of both tensile failure and 

shear failure in the confining zone. We also agree that limits must be designed 

to avoid causing otherwise non-transmissive faults to become transmissive, in 

addition to addressing the more traditional concern of avoiding the initiation 

or propagation of fractures. 
Response: EPA notes that because determination of the injection pressure limit is based on the

fracture pressure of the injection zone, the limit is site-specific and not arbitrary. EPA emphasizes

that injection pressure limits are important to protect against fracturing of the confining zone, and

that the requirement at §146.88(a) that the pressure in the injection zone not exceed 90 percent of the

fracture pressure provides a margin of safety in the well operation and protects USDWs from

endangerment. If the Director determines, based on a review of the information collected as part of

site characterization, that a lower injection pressure limitation is appropriate, the Director has the

authority to set a lower limit in the operating permit than the limit established in the rule. 

EPA notes that during the site characterization process, owners or operators must submit data about

the geology of the site, as specified at §146.82(a), including data on known or suspected faults and

fractures and geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid

pressures within the confining zone. The Director will use these data to determine appropriate limits

on injection. 

In response to the concern about reopening of faults at lower pressures than 90 percent of fracture

pressure, EPA believes that the requirement for the owner or operator to submit data on known or

suspected faults and fractures and information on the seismic history of the site will inform the

determination of an appropriate pressure limitation in the permit. Any sites with the potential for

reopening or reactivation of faults or unacceptable seismic risk that could otherwise interfere with

containment will not be permitted as GS sites.

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24909

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88 

EPA Proposal: 8. Injection well operating requirements 

(a) Except during stimulation, the owner or operator must ensure that injection 

pressure does not exceed 90 percent of the fracture pressure of the injection 

zone so as to assure that the injection does not initiate new fractures or 

propagate existing fractures in the injection zone. In no case may injection 

pressure initiate fractures in the confining zone(s) or cause the movement of 

injection or formation fluids that endangers a USDW. 

GWPC Recommendations: (a) The owner or operator must comply with a maximum 

injection pressure limit approved by the Director and specified in the permit. 

In approving a maximum injection pressure limit, the Director shall consider the 
results of well tests and, where appropriate, geomechanical or other studies 

that assess the risks of tensile failure and shear failure. The Director shall 

approve limits that, with a reasonable degree of certainty, will avoid 

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

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

In no case may injection pressure cause movement of injection or formation 

fluids in a manner prohibited by 40 CFR Part 144.12(a). 

Rationale: Maintaining the integrity of the confining zone is the critical 

parameter. We believe establishing a maximum pressure based on an arbitrary 

percentage of injection zone fracture pressure does not address the issue of 

confining zone integrity in an appropriate way. 

Response: EPA notes that because determination of the injection pressure limit is based on the

fracture pressure of the injection zone, the limit is site-specific and not arbitrary. EPA emphasizes

that injection pressure limits are important to protect against fracturing of the confining zone, and

that the requirement at §146.88(a) that the pressure in the injection zone not exceed 90 percent of the

fracture pressure provides a margin of safety in the well operation and protects USDWs from

endangerment. If the Director determines, based on a review of the information collected as part of

site characterization, that a lower injection pressure limitation is appropriate, the Director has the

authority to set a lower limit in the operating permit than the limit established in the rule. 

EPA notes that during the site characterization process, owners or operators must submit data about

the geology of the site, as specified at §146.82(a), including data on known or suspected faults and

fractures and geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid

pressures within the confining zone. The Director will use these data to determine appropriate limits

on injection. 

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: David Hawkins Letter ID: 0272

Commenter Organization: Natural Resources Defense Council Comment ID: 24078

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: C. Pressure management 

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

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

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

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

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

geologic factors each time, which we attempt to incorporate in the proposed 
language below. Nonetheless, we believe that EPA should maintain a maximum upper 

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

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

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

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

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

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

starting point: 

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

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

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

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

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

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

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

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

otherwise non-transmissive faults transecting the confining zone to become 

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

formation fluids that endangers a USDW." 

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

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

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

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

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

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

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

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

transparent and capable of screening adequate tests from inadequate ones. 

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

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

pressure limits. 

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

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

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

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

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

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

Response: EPA disagrees with the suggestion that injection pressure be set at less than 90 percent of

fracture pressure. EPA believes that a lower pressure limitation may not allow for sufficient volumes

of CO2 to be transmitted away from the well and into the injection formation. EPA acknowledges

that there may be circumstances where a lower pressure limitation may be appropriate; in such cases,

the Director has the authority, at §146.88, to set a lower pressure limit in the operating permit. EPA

believes that the 90 percent requirement allows the consideration of site-specific circumstances and

provides a satisfactory margin of safety during well operation. 

EPA clarifies that injection pressure limit for each GS project will be based on site-specific
conditions, and be informed by data on the injection and confining zones. During injection, the

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

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

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

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

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

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

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

pressure limit at 90 percent of this value. 

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

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

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

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

prohibited at §146.88(a).

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

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

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

submit a proposed stimulation program as part of the permit application under §146.82(a)(9); the

plan must demonstrate that any stimulation activities will not compromise the integrity of the

confining zone. The Director will evaluate the owner or operator's proposed stimulation plan in the

context of all information about the site, and the owner or operator must perform stimulation only as

approved. 

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: A. Scott Anderson Letter ID: 0293

Commenter Organization: Environmental Defense Fund Comment ID: 25279

Comment: (2). Appropriate pressure management is essential if a GS project is to perform 

properly. In highly pressured reservoirs, it is vital that EPA assure that 

regulators and operators will consider both the risks of tensile failure and 

shear failure. UIC regulation has tended, at least in practice, to focus only on 

the former. For these and other reasons, we urge you to carefully consider the 

suggestions for injection pressure limitations that the Multi-Stakeholder Group 

forwarded on December 23; 

Response: EPA agrees that pressure management is essential for a Class VI well to perform

properly. EPA emphasizes that injection pressure limits are important to protect against fracturing of

the confining zone, and that the requirement at §146.88(a) that the pressure in the injection zone not

exceed 90 percent of the fracture pressure provides a margin of safety in the well operation and

protects USDWs from endangerment. If the Director determines, based on a review of the
information collected as part of site characterization, that a lower injection pressure limitation is

appropriate, the Director has the authority to set a lower limit in the operating permit than the limit

established in the rule. 

EPA notes that during the site characterization process, owners or operators must submit data about

the geology of the site, as specified at §146.82(a), including data on known or suspected faults and

fractures and geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid

pressures within the confining zone. The Director will use these data to determine appropriate limits

on injection. 

In response to the concern about reopening of faults at lower pressures than 90 percent of fracture

pressure, EPA believes that the requirement for the owner or operator to submit data on known or

suspected faults and fractures and information on the seismic history of the site will inform the

determination of an appropriate pressure limitation in the permit. Any sites with the potential for

reopening or reactivation of faults or unacceptable seismic risk that could otherwise interfere with

containment will not be permitted as GS sites.

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: Scott Anderson Letter ID: 0510

Commenter Organization: Environmental Defense Fund Comment ID: 21229

Comment: One minute and two more comments. We think injection pressure limits need to 

expressly require the consideration of geo-mechanical information, not just the 

90 percent of fracture pressure. A rule that is expressed in terms of 

percentage of fracture pressure ignores things like induced seismicity and the 

re-opening of faults. We think -- sophisticated -- pressure than a requirement. 

Response: EPA notes that because determination of the injection pressure limit is based on the

fracture pressure of the injection zone, the limit is site-specific and not arbitrary. EPA emphasizes

that injection pressure limits are important to protect against fracturing of the confining zone, and

that the requirement at §146.88(a) that the pressure in the injection zone not exceed 90 percent of the

fracture pressure provides a margin of safety in the well operation and protects USDWs from

endangerment. If the Director determines, based on a review of the information collected as part of

site characterization, that a lower injection pressure limitation is appropriate, the Director has the

authority to set a lower limit in the operating permit than the limit established in the rule. 

EPA notes that during the site characterization process, owners or operators must submit data about

the geology of the site, as specified at §146.82(a), including data on known or suspected faults and

fractures and geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid

pressures within the confining zone. The Director will use these data to determine appropriate limits

on injection. 
In response to the concern about reopening of faults at lower pressures than 90 percent of fracture

pressure, EPA believes that the requirement for the owner or operator to submit data on known or

suspected faults and fractures and information on the seismic history of the site will inform the

determination of an appropriate pressure limitation in the permit. Any sites with the potential for

reopening or reactivation of faults or unacceptable seismic risk that could otherwise interfere with

containment will not be permitted as GS sites.

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

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

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

Commenter Name: Scott Anderson Letter ID: 0520

Commenter Organization: Environmental Defense Fund Comment ID: 21431

Other EPA Comment Codes and Descriptions: 1620 1.3.2 Induced seismicity; 4710 2.7.1

Proposed submissions required for permit applications (seeking comment) 

Comment: Injection pressure limits. This is very important and we think EPA's about 

halfway toward addressing this properly. The half that seems to be well done is 

that the proposed rule requires quite a bit of geomechanical information to be 

submitted. The kind of information that could be used, should be used to 

determine whether or not there is a risk of induced seismicity and to determine 

whether or not there is risks of reopening otherwise closed faults and fractures 

making them, making what starts out as a non-transmissive fault into a 

transmissive fault. So the proposed rule calls for the information that enables 

that kind of stuff to be calculated, but it fails to require that information to 

be used as part of the permitting process to inform the injection pressure 

limits. Instead the rule uses the traditional sort of injection pressure limit 

from oil and gas regulation that says accepted as a percentage of fracture 

pressure. The problem with that is that these other problems I mentioned, 

induced seismicity and reopening of faults can occur in lower pressures than say 

90% of fracture pressure, it is possible for one to comply with the 90% of 

fracture pressure requirement and yet still cause these other geomechanics 

related problems. 

Response: EPA clarifies that all information about the site, including seismic history and data on

rock mechanics, will be used to inform pressure limitations. 

In response to the concern about induced seismicity and reopening of faults at lower pressures than

90 percent of fracture pressure, EPA believes that the requirement for the owner or operator to

submit data on known or suspected faults and fractures and information on the seismic history of the

site, including the presence and depth of seismic sources and a determination that the seismicity

would not interfere with containment per §146.82(a)(3)(v), will inform the determination of an

appropriate pressure limitation in the permit. This investigation would also identify any sites with the

potential for reopening or reactivation of faults or unacceptable seismic risk that could otherwise

interfere with containment. 
The Director will also review geologic, hydrogeologic, and geomechanical information submitted by

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

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

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

prohibited at §146.88(a).

Comment Code: 4120 2.4.1.2 Allowing hydraulic fracturing during GS (seeking comment) 

Individual Comments

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141

Commenter Organization: Global Energy, Inc. Comment ID: 23116

Comment: Well Operation 

1.We do not believe that hydraulic fracturing should be restricted or prohibited 

where it can be demonstrated that existing faults are sufficiently remote from 

the injection site or the geology is otherwise appropriate for it. 

2.Similarly, we also believe that the geology itself can inform the siting 

process and application as to whether fracturing will be appropriate, even 

without existing faults in proximity to the well location. 

Response: The final rule allows the use of hydraulic fracturing for purposes of Class VI injection,

where approved by the Director. Hydraulic fracturing is one of several stimulation technologies

available to improve wellbore and formation injectivity. 

EPA agrees that site-specific information will inform the siting process and decisions about whether

fracturing is appropriate. Owners or operators must submit a proposed stimulation program as part of

the permit application under §146.82(a)(9); the plan must demonstrate that any stimulation activities

will not compromise the integrity of the confining zone. The Director will evaluate the owner or

operator's proposed stimulation plan in the context of all information about the site, and the owner or

operator must perform stimulation only as approved. 

EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director

and that §146.88(a) permits injection pressure to exceed 90 percent of the fracture pressure only

during well stimulation. The final rule at §146.91(d)(2) also requires that the owner or operator

notify the Director 30 days before performing stimulation during the operational phase of a GS

project; this will provide an additional opportunity for the 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 in order to

protect USDWs from endangerment.

Commenter Name: Larry Myer Letter ID:

0149

Commenter Organization: Lawrence Berkeley National Laboratory (Berkeley Lab)

U.S. Department of Energy (DOE)

Comment ID:

21798
Comment: The requirement that injection pressure should not exceed 90 percent of fracture 

pressure is also unnecessarily conservative and restrictive because it precludes 

use of hydrofracturing as a reservoir stimulation technique. It is important 

that the seal not be fractured, but purposeful fracturing of the injection 

interval will likely be advantageous in many instances, just as it is in 

hydrocarbon production. Carefully engineered hydrofracturing operations carried 

out in conjunction with a monitoring program, should be allowed. 

Response: EPA clarifies that the injection pressure limit at §146.88(a) applies only to the period of

injection, not well stimulation. In addition, EPA recognizes that there may be well completions

which require intermittent treatments that include stimulation to improve wellbore injectivity.

Stimulation of the injection zone during a well workover will be permissible, if approved by the

Director (operators seeking to use stimulation must submit the proposed stimulation program as part

of the permit application under §146.82(a)(9)). EPA has also added a requirement that owners or

operators notify the Director in advance of any planned stimulation activities, as specified at

§146.91(d). During injection, the injection pressure must not exceed 90 percent of the fracture

pressure, as specified in §146.88(a). EPA clarifies that the injection pressure limit at §146.88(a)

applies only to the period of injection, not well stimulation.

Commenter Name: James Dooley Letter ID: 0156

Commenter Organization: Joint Global Change Research Institute, Pacific

Northwest National Laboratory

Comment ID:

22640

Comment: More importantly did the USEPA intend to tie this 90% pressure threshold to the 

fracture pressure of the "injection zone" or the fracture pressure of the 

"primary caprock / seal above the injection zone"? If a GS project was 

injecting at the bottom of a 500 meter thick interval of a sandstone, is there 

any harm in allowing for some amount of deformation to areas near the injection 

point in the target formation? In many areas, the caprocks are stronger than 

the injection zones based on the rock types, degree of cementation etc. In such 

cases, it may be good to have a mechanism where you can stimulate the injection 

zone more aggressively to increase permeability / injectivity. Fracturing of 

the injection zones may be critical in improving injection performance and even 

in making some of the marginal injectivity sites into viable sites. 

Response: EPA clarifies that the injection pressure must not exceed 90 percent of the fracture

pressure of the injection zone. The final rule retains this provision at §146.88(a). EPA believes that

the 90 percent requirement, which was suggested by state representatives whom EPA consulted

when writing the regulation, is a satisfactory margin of safety for well operation. 

EPA recognizes that there may be well completions which require intermittent treatments that

include stimulation to improve wellbore injectivity. Stimulation of the injection zone during a well

workover will be permissible, if approved by the Director (operators seeking to use stimulation must

submit the proposed stimulation program as part of the permit application under §146.82(a)(9) where

injection pressure limits will be set). EPA has also added a requirement that owners or operators

notify the Director in advance of any planned stimulation activities, as specified at §146.91(d).

During injection, the injection pressure must not exceed 90 percent of the fracture pressure, as

specified in §146.88(a). EPA clarifies that the injection pressure limit at §146.88(a) applies only to

the period of injection, not well stimulation.
Commenter Name: James Childress Letter ID: 0158

Commenter Organization: Gasification Technologies Council (GTC) Comment ID: 23783

Comment: EPA is requesting comment on the extent and scope to which hydraulic fracturing 

should be allowed during GS injection, and whether the use of fracturing for the 

purposes of well stimulation is appropriate. EPA Notice 85. 

Fracturing of GS formations should be permitted, provided confining structures 

are not negatively impacted and fracturing is limited to the injection zone. 

Exclusion of fracturing of storage formations would often require unnecessary 

drilling of new injection wells. The oil industry has sufficient experience in 

using fracturing technology to avoid negatively impacting confining structures 

(e.g., caprock). 

Response: EPA recognizes that there may be well completions which require intermittent treatments

that include stimulation to improve wellbore injectivity. Stimulation of the injection zone during a

well workover will be permissible, if approved by the Director (operators seeking to use stimulation

must submit the proposed stimulation program as part of the permit application under §146.82(a)(9)

where injection pressure limits will be set). EPA has also added a requirement that owners or

operators notify the Director in advance of any planned stimulation activities, as specified at

§146.91(d). During injection, the injection pressure must not exceed 90 percent of the fracture

pressure, as specified in §146.88(a). EPA clarifies that the injection pressure limit at §146.88(a)

applies only to the period of injection, not well stimulation.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24236

Comment: Rule Provisions: 73 FR 43511 

EPA Preamble Question: 21. EPA is also requesting information to better qualify 

the use of fracturing for GS injection in specific geologic settings and rock 

formation lithologies. EPA Notice 43511. 

API Response: See response to #20. 

Response: As described above, the final rule allows fracturing only during stimulation. At

§146.88(a), the rule language states that the injection pressure may not exceed 90 percent of the

fracture pressure of the injection zone, except during stimulation.

Commenter Name: James Rower Letter ID: 0173

Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23496

Comment: Hydraulic fracturing - While hydraulic fracturing is not appropriate in all 

geologic settings, it should be an available option, subject to approval of the 

Director. See id. at 43511. For years, EOR operations have employed hydraulic 

fracturing to enlarge fractures in rock; hydraulic fracturing has proven an 

effective way to create permeability and increase well capacity with minimal 

risk to USDWs. Because this technique has been used safely for many years, there 

are regulatory protocols in place that could be adopted to ensure safe and 

effective hydraulic fracturing where appropriate for Class VI CO2 GS operations. 

When used where appropriate, hydraulic fracturing increases the capacity of 

existing wells, thereby requiring fewer cap rock penetrations and fewer wells 
overall. Again, USWAG shares EPA's underlying goal of protecting USDWs, and 

recognizes that hydraulic fracturing may not meet this standard in some 

situations; we ask only that the opportunity remain for use of hydraulic 

fracturing at the Director's discretion and only when the Owner or Operator can 

demonstrate that such fracturing will not jeopardize USDWs. 

Response: The final rule allows the use of hydraulic fracturing for purposes of Class VI injection,

where approved by the Director. Hydraulic fracturing is one of several stimulation technologies

available to improve wellbore and formation injectivity. 

EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director

and that §146.88(a) permits injection pressure to exceed 90 percent of the fracture pressure only

during well stimulation. Owners or operators must submit a proposed stimulation program as part of

the permit application under §146.82(a)(9); the plan must demonstrate that any stimulation activities

will not compromise the integrity of the confining zone. The Director will evaluate the owner or

operator's proposed stimulation plan in the context of all information about the site, and the owner or

operator must perform stimulation only as approved. EPA clarifies that UIC regulations prohibit

fracturing of the confining zone at any time during injection or stimulation.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23645

Comment: - Hydraulic fracturing should not be used at all for GS; 

Response: EPA emphasizes that fracturing of the confining zone during injection and/or stimulation

is prohibited, as specified at §146.88(a). However, EPA believes there are some circumstances where

fracturing of the injection zone is acceptable, provided the integrity of the confining system remains

unaffected. The final rule allows the use of hydraulic fracturing at GS sites, where approved by the

Director. Hydraulic fracturing is one of several stimulation technologies available to improve

wellbore and formation injectivity. 

EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director.

Owners or operators must submit a proposed stimulation program as part of the permit application

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

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

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

perform stimulation only as approved. 

The final rule at §146.91(d)(2) also requires that the owner or operator notify the Director 30 days

before performing stimulation during the operational phase of a GS project; this will provide an

additional opportunity for the Director to review the owner or operator's plans for stimulation and

add other requirements as needed.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23695

Other EPA Comment Codes and Descriptions: 4130 2.4.1.3 Appropriateness of using fracturing

for well stimulation (seeking comment) 

Comment: Category: Hydraulic Fracturing 
EPA Request for Comment: EPA is requesting comment on the extent and scope to 

hich hydraulic fracturing should be allowed during GS injection, and whether 

the use of fracturing for the purposes of well stimulation is appropriate. EPA 

Notice 43511. 

AWWA Response: Hydraulic fracturing during carbon dioxide injection has the 

potential to serious compromise the confining layer and AWWA recommends that 

this practice should not be allowed as part of the injection process. The 

objective of characterizing the injection and confining zones is to find a 

location that is free from faults, penetrations or other physical methods by 

which carbon dioxide could escape. Hydraulic fracturing creates fractures in the 

injection zone, and possibly the confining layer, which would allow for a 

pathway by which carbon dioxide could migrate into USDWs. Therefore, AWWA 

recommends that this process not be utilized at all in geologic carbon 

sequestration. 

Response: EPA emphasizes that fracturing of the confining zone during injection and/or stimulation

is prohibited, as specified at §146.88(a). However, as described above, EPA believes there may be

some circumstances where fracturing of the injection zone may be acceptable, provided the integrity

of the confining system remains unaffected. The final rule allows the use of hydraulic fracturing at

GS sites, where approved by the Director. Hydraulic fracturing is one of several stimulation

technologies available to improve wellbore and formation injectivity.

Commenter Name: Daniel Plath Letter ID: 0188

Commenter Organization: NiSource, Inc. Comment ID: 25235

Other EPA Comment Codes and Descriptions: 3840 2.3.2 Horizontal well drilling techniques

(seeking comment) 

Comment: 2. Horizontal Well Construction and Injection Parameter Limitations (73 Fed. 

Reg. at 43509 and 43510) 

The EPA is inclined to permit hydraulic fracturing (frac jobs) and horizontal 

wells and asks for comments on permitting these technologies. NiSource strongly 

believes they should be permitted in addition to similar new technologies that 

will be developed sometime in the future. 

Columbia has successfully performed thousands of fracs and refracs in addition 

to drilling numerous horizontal and other non-vertical types of wells. One of 

the keys to ensure gas confinement is to have the fewest number of penetrations 

of the cap rock. Both frac jobs and horizontal wells permit significantly 

greater injectability from a single well. Our experience is that this type of 

work can increase injectability by 2 to 8 times or to phrase it differently, 

only one- eighth to one-half the number of wells would be required to match the 

equivalent performance of vertical wells or non-stimulated wells. 

Whatever technologies that can be employed, whether existing or new, to reduce 

the number of penetrations are valuable from a surface environmental impact, 

landowner acceptance, and cost management perspective and should be allowed by 

this regulation. 
Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed

rule, EPA sought comment on the appropriateness of horizontal drilling techniques for Class VI

wells, and commenters representing energy companies, electric utilities, the oil and gas industry,

CCS associations, states, and the public, unanimously supported the concept and provided many

reasons why horizontal wells could be beneficial at GS sites. Based on an evaluation of these

comments and additional research by EPA, the Agency has concluded that horizontal wells that are

properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of

the GS rule) can ensure the protection of USDWs from endangerment.

The final rule allows the use of hydraulic fracturing for purposes of Class VI injection, where

approved by the Director. Hydraulic fracturing is one of several stimulation technologies available to

improve wellbore and formation injectivity. 

EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director

and that §146.88(a) permits injection pressure to exceed 90 percent of the fracture pressure only

during well stimulation. Owners or operators must submit a proposed stimulation program as part of

the permit application under §146.82(a)(9); the plan must demonstrate that any stimulation activities

will not compromise the integrity of the confining zone. The Director will evaluate the owner or

operator's proposed stimulation plan in the context of all information about the site, and the owner or

operator must perform stimulation only as approved. 

The final rule at §146.91(d)(2) also requires that the owner or operator notify the Director 30 days

before performing stimulation during the operational phase of a GS project; this will provide an

additional opportunity for the 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24528

Comment: Rule Provisions or Federal Register Cite: 73 FR 43511 

EPA Preamble Question: 21. EPA is also requesting information to better qualify 

the use of fracturing for GS injection in specific geologic settings and rock 

formation lithologies. EPA Notice 43511. 

CSC Response: EPA should allow fracturing for stimulation and should set 

injection pressure limits to preclude initiating, propagating, or opening 

avenues of release through fractures transecting the confining zone. 

Response: EPA recognizes that there may be well completions which require intermittent treatments

that include stimulation to improve wellbore injectivity. Stimulation of the injection zone during a

well workover will be permissible, if approved by the Director (operators seeking to use stimulation

must submit the proposed stimulation program as part of the permit application under §146.82(a)(9)).

EPA has also added a requirement that owners or operators notify the Director in advance of any

planned stimulation activities, as specified at §146.91(d). 

EPA clarifies that the injection pressure may not exceed 90 percent of the fracture pressure of the

injection zone. The final rule retains this provision at §146.88(a). EPA believes that the 90 percent

requirement, which was suggested by state representatives and permit writers whom EPA consulted

when writing the regulation, is a satisfactory margin of safety for well operation. 
In addition, to maintain the integrity of the confining zone, the final rule requires that, except during

stimulation, the injection pressure not exceed 90 percent of the fracture pressure of the injection

zone.

Commenter Name: John R. Baza Letter ID: 0193

Commenter Organization: Utah Division of Oil, Gas, and Mining Comment ID: 23914

Other EPA Comment Codes and Descriptions: 4344 2.4.4.2.2 Comments opposed to setting a

minimum injection depth; 4490 2.4.5 Use of tracers and potential impact on human health or

ecosystems (seeking comment) 

Comment: Operating Requirements 

EPA seeks comments on hydraulic fracturing, minimum depth requirements, and the 

potential impact of tracer use on human health and the environment. The Division 

concurs with the IOGCC recommendations (included in their December 23, 2008 

comments) that while hydraulic fracturing may be necessary for well completion, 

measures should be taken to prevent any fracturing of the confining zone. No 

minimum depth for GS should be specified and once again should be done on a 

site-specific basis. Use of tracers should be at the discretion of the 

regulating agency. 

Response: The final rule allows the use of hydraulic fracturing at Class VI well sites, where

approved by the Director. Hydraulic fracturing is one of several stimulation technologies available to

improve wellbore and formation injectivity. 

EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director.

Owners or operators must submit a proposed stimulation program as part of the permit application

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

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

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

perform stimulation only as approved. 

The final rule at §146.91(d)(2) also requires that the owner or operator notify the Director 30 days

before performing stimulation during the operational phase of a GS project; this will provide an

additional opportunity for the 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.

In addition, to maintain the integrity of the confining zone, the final rule requires that, except during

stimulation, the injection pressure not exceed 90 percent of the fracture pressure of the injection

zone.

EPA also agrees that it is not appropriate to set a minimum injection depth for GS projects and the

Agency believes that a determination of site-suitability for GS (i.e., that subsurface formations will

receive and confine injected CO2) should be made on a site-specific basis. The GS rule at §146.82

requires the owner or operator to provide extensive site- and project-specific information to the

Director to demonstrate that the site meets the minimum siting criteria at §146.83 and that the CO2

will be contained within the injection formation and that USDWs will be protected from

endangerment. 
EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Finally, EPA agrees that the use of tracers should not be required at all GS sites, but should be

available as an option. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment. The rule

will also allow their use if proposed by the owner or operator and approved by the Director.

Commenter Name: Paul Pike Letter ID: 0198

Commenter Organization: Ameren Corporation Comment ID: 23952

Comment: While hydraulic fracturing is not appropriate in all geologic settings, it 

should be an available option. For years, EOR operations have employed 

hydraulic fracturing to enlarge fractures in rock; hydraulic fracturing has 

proven an effective way to create permeability and increase well capacity with 

minimal risk to USDWs. This technique has been used for many years, and we 

believe that regulatory protocols could be established to ensure safe and 

effective hydraulic fracturing where appropriate for Class VI CO2 GS operations. 

A gain, hydraulic fracturing would only be used when the Owner or Operator can 

demonstrate that such fracturing will not jeopardize USDWs or other important 

subsurface activities 

Response: The final rule allows the use of hydraulic fracturing at GS sites, where approved by the

Director. Hydraulic fracturing is one of several stimulation technologies available to improve

wellbore and formation injectivity. 

EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director.

Owners or operators must submit a proposed stimulation program as part of the permit application

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

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

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

perform stimulation only as approved. 

The final rule at §146.91(d)(2) also requires that the owner or operator notify the Director 30 days

before performing stimulation during the operational phase of a GS project; this will provide an

additional opportunity for the 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 in order to protect USDWs from
endangerment.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24591

Comment: Rule Provisions: 73 FR 43511 

EPA Rule Issue: 21. EPA is also requesting information to better qualify the use 

of fracturing for GS injection in specific geologic settings and rock formation 

lithologies. EPA Notice 43511. 

Anadarko Petroleum Corporation (APC) Response: See response to EPA Notice 43511. 

Response: As described above, the final rule allows fracturing only during stimulation and where

the Director approves such action. At §146.88(a), the rule language states that the injection pressure

may not exceed 90 percent of the fracture pressure of the injection zone, except during stimulation.

Commenter Name: Richard Guinn Letter ID: 0210

Commenter Organization: Eastman Chemical Company Comment ID: 22733

Other EPA Comment Codes and Descriptions: 4130 2.4.1.3 Appropriateness of using fracturing

for well stimulation (seeking comment) 

Comment: EPA is requesting comment on the extent and scope to which hydraulic fracturing 

should be allowed during GS injection, and whether the use of fracturing for the 

purposes of well stimulation is appropriate. EPA Notice 85. 

Fracturing of GS formations should be permitted, provided confining structures 

are not negatively impacted and fracturing is limited to the injection zone. 

Exclusion of fracturing of storage formations would often require unnecessary 

drilling of new injection wells. The oil industry has sufficient experience in 

using fracturing technology to avoid negatively impacting confining structures 

(e.g., caprock). 

Response: EPA recognizes that there may be well completions which require intermittent treatments

that include stimulation to improve wellbore injectivity. Stimulation of the injection zone during a

well workover will be permissible, if approved by the Director (operators seeking to use stimulation

must submit the proposed stimulation program as part of the permit application under §146.82(a)(9)

where injection pressure limits will be set). EPA has also added a requirement that owners or

operators notify the Director in advance of any planned stimulation activities, as specified at

§146.91(d). During injection, the injection pressure must not exceed 90 percent of the fracture

pressure, as specified in §146.88(a). EPA clarifies that the injection pressure limit at §146.88(a)

applies only to the period of injection, not well stimulation.

Commenter Name: John King Letter ID: 0211

Commenter Organization: Shell Exploration and Production Company

(SEPCo)

Comment ID:

22772

Other EPA Comment Codes and Descriptions: 4110 2.4.1.1 Injection pressure limitations 

Comment: D. Injection Well Operating Requirements 

1. Injection Pressure Limitations 
Under the existing UIC regulations, permits for Class II injection wells must 

limit injection pressure as follows: 

Injection pressure at the wellhead shall not exceed a maximum, which shall be 

calculated so as to assure that the pressure during injection does not initiate 

new fractures or propagate existing fractures in the confining zone adjacent to 

the USDWs. In no case shall injection pressure cause the movement of injection 

or formation fluids into an underground source of drinking water. 

40 C.F.R. 146.23(a)(1). This has proven to be an effective regulatory 

requirement that provides a flexible and appropriate performance standard to be 

applied on the basis of site-specific conditions. This regulatory approach has 

proved successful in the Class II context, and there is no basis to conclude 

that a similar standard would not be appropriate in the context of carbon 

sequestration. 

The Class I requirements impose more restrictive requirements designed not just 

to prevent endangerment of USDWs, but to ensure that there is no fracturing in 

the injection zone during normal operation. The latter requirement may make 

sense when "no migration" exemptions depend upon the integrity of confining or 

"arrestment" strata within the injection zone, but such a requirement is 

certainly more rigid than necessary to prevent endangerment of USDWs. 

Accordingly, such a standard is not necessary in the context of carbon 

sequestration, and would be ill-suited in a rule that must have the flexibility 

to address a wide range of potential injection scenarios. 

Recommendation: 

Injection pressure limitations for Class VI injection wells should be based on 

the existing Class II requirements, modified slightly to address the possibility 

of Class VI injection occurring above the lowermost USDW. We recommend the 

following specific language: 

Injection pressure at the wellhead shall not exceed a maximum, which shall be 

calculated so as to assure that the pressure during injection does not initiate 

new fractures or propagate existing fractures in the confining zone. In no case 

shall injection pressure cause movement of injection or formation fluids that 

endangers an underground source of drinking water. 

Response: EPA believes that the injection pressure limits in the GS rule are important to protect

against fracturing of the confining zone, and that the requirement at §146.88(a) that the pressure in

the injection zone not exceed 90 percent of the fracture pressure provides a margin of safety in the

well operation and protects USDWs from endangerment. 

The pressure limitations are tailored to the unique nature of CO2 injection for GS and afford

flexibility to address site-specific circumstances. EPA notes that during the site characterization

process, owners or operators must submit data about the geology of the site, as specified at

§146.82(a), including data on known or suspected faults and fractures and geomechanical

information on fractures, stress, ductility, rock strength, and in situ fluid pressures within the

confining zone. The Director will use these data to determine appropriate limits on injection. 
EPA is developing guidance on site characterization for GS projects to assist owners or operators in

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

guidance will describe recommended approaches for characterizing the regional geology and

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

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

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

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. The Department of Energy is

developing a Best Practices Manual on site characterization.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23242

Other EPA Comment Codes and Descriptions: 4130 2.4.1.3 Appropriateness of using fracturing

for well stimulation (seeking comment) 

Comment: 20. EPA is requesting comment on the extent and scope to which hydraulic 

fracturing should be allowed during GS injection and whether the use of 

fracturing for the purposes of well stimulation is appropriate. EPA Notice 

43511. 

Hydraulic fracturing should be allowed as long as it does not compromise the 

confining zone. Computer modeling to predict the fracture growth can be 

utilized in fracture stimulation design. 

Response: EPA agrees that stimulation, such as hydraulic fracturing should be permitted in some

situations, and the final rule allows the use of hydraulic fracturing at GS sites, where approved by

the Director. Hydraulic fracturing is one of several stimulation technologies available to improve

wellbore and formation injectivity. EPA clarifies that fracturing is permitted during stimulation, but

not during injection. During injection, the injection pressure must not exceed 90 percent of the

fracture pressure, as specified in §146.88(a).

All stimulation, including hydraulic fracturing, must be approved by the Director. Owners or

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

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

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

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

perform stimulation only as approved. It is possible that computer simulations may support this

determination to the Director's satisfaction. EPA clarifies that all data submitted with the permit

application, including modeling of the AoR, will inform the Director's decision on whether hydraulic

fracturing is acceptable at a GS site.

Letter ID: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22806

Other EPA Comment Codes and Descriptions: 4130 2.4.1.3 Appropriateness of using fracturing

for well stimulation (seeking comment) 

Comment: III A. 4 Proposed Injection Well Operating Requirements 

U. EPA is requesting comment on the extent and scope to which hydraulic fracturing 
should be allowed during GS injection, and whether the use of fracturing for the 

purposes of well stimulation is appropriate. 

IOGCC Response: While hydraulic fracturing maybe necessary in some cases to 

complete an injection well, it should not be allowed during GS injection. 

Any fracturing during well completion stimulation should be engineered so as to 

eliminate any risk of damage to confining zones. 

Response: EPA emphasizes that fracturing of the confining zone during injection and/or stimulation

is prohibited, as specified at §146.88(a). However, EPA believes there are some circumstances where

fracturing of the injection zone may be acceptable, provided the integrity of the confining system

remains unaffected and maintains USDW protection. EPA clarifies that §146.88(a) permits injection

pressure to exceed 90 percent of the fracture pressure only during well stimulation. The final rule

allows the use of hydraulic fracturing at GS sites, where approved by the Director. Hydraulic

fracturing is one of several stimulation technologies available to improve wellbore and formation

injectivity. 

EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director.

Owners or operators must submit a proposed stimulation program as part of the permit application

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

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

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

perform stimulation only as approved. 

The final rule at §146.91(d)(2) also requires that the owner or operator notify the Director 30 days

before performing stimulation during the operational phase of a GS project; this will provide an

additional opportunity for the Director to review the owner or operator's plans for stimulation and

add other requirements as needed.

Commenter Name: Steven Chester Letter ID: 0264

Commenter Organization: Michigan Department of Environmental Quality

(MDEQ)

Comment ID:

22838

Comment: EPA (III. A. 4.) proposes allowing hydraulic fracturing in GS wells. 

- Staff believes hydraulic fracturing should be allowed to improve 

well bore injectivity when necessary so long as fracturing of the confining 

zone(s) is prohibited at all times. 

Response: The final rule allows the use of hydraulic fracturing at Class VI well sites, where

approved by the Director. Hydraulic fracturing is one of several stimulation technologies available to

improve wellbore and formation injectivity. EPA clarifies that fracturing is permitted during

stimulation, but not during injection. During injection, the injection pressure must not exceed 90

percent of the fracture pressure, as specified in §146.88(a).

EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director.

Owners or operators must submit a proposed stimulation program as part of the permit application

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

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

stimulation plan in the context of all information about the site, and the owner or operator must
perform stimulation only as approved. 

The final rule at §146.91(d)(2) also requires that the owner or operator notify the Director 30 days

before performing stimulation during the operational phase of a GS project; this will provide an

additional opportunity for the 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.

Comment Code: 4130 2.4.1.3 Appropriateness of using fracturing for well stimulation (seeking

comment) 

Individual Comments

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24235

Comment: Rule Provisions: 146.88(a) 

EPA Preamble Question: 20. EPA is requesting comment on the extent and scope to 

which hydraulic fracturing should be allowed during GS injection, and whether 

the use of fracturing for the purposes of well stimulation is appropriate. EPA 

Notice 43511. 

API Response: The use of fracturing for stimulation should be allowed provided 

that there is no damage to the confining unit that would result in endangerment 

of USDWs. There are computer simulators to predict fracture behavior so the 

impact on the confining zone can be anticipated. 

Response: EPA agrees that stimulation should be permitted in some situations and the final rule

allows the use of hydraulic fracturing at GS sites, where approved by the Director. Hydraulic

fracturing is one of several stimulation technologies available to improve wellbore and formation

injectivity. EPA clarifies that fracturing is permitted during stimulation, but not during injection.

During injection, the injection pressure must not exceed 90 percent of the fracture pressure, as

specified in §146.88(a).

All stimulation, including hydraulic fracturing, must be approved by the Director. Owners or

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

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

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

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

perform stimulation only as approved. It is possible that computer simulations may support this

determination to the Director's satisfaction. EPA clarifies that all data submitted with the permit

application, including modeling of the AoR, will inform the Director's decision on whether hydraulic

fracturing is acceptable at a GS site.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23695

Other EPA Comment Codes and Descriptions: 4120 2.4.1.2 Allowing hydraulic fracturing during

GS (seeking comment) 
Comment: Category: Hydraulic Fracturing 

EPA Request for Comment: EPA is requesting comment on the extent and scope to 

hich hydraulic fracturing should be allowed during GS injection, and whether 

the use of fracturing for the purposes of well stimulation is appropriate. EPA 

Notice 43511. 

AWWA Response: Hydraulic fracturing during carbon dioxide injection has the 

potential to serious compromise the confining layer and AWWA recommends that 

this practice should not be allowed as part of the injection process. The 

objective of characterizing the injection and confining zones is to find a 

location that is free from faults, penetrations or other physical methods by 

which carbon dioxide could escape. Hydraulic fracturing creates fractures in the 

injection zone, and possibly the confining layer, which would allow for a 

pathway by which carbon dioxide could migrate into USDWs. Therefore, AWWA 

recommends that this process not be utilized at all in geologic carbon 

sequestration. 

Response: EPA emphasizes that fracturing of the confining zone during injection and/or stimulation

is prohibited, as specified at §146.88(a). However, as described above, EPA believes there may be

some circumstances where fracturing of the injection zone may be acceptable, provided the integrity

of the confining system remains unaffected. The final rule allows the use of hydraulic fracturing at

GS sites, where approved by the Director. Hydraulic fracturing is one of several stimulation

technologies available to improve wellbore and formation injectivity.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25190

Comment: S. EPA is requesting comment on the extent and scope to which hydraulic 

fracturing should be allowed during GS injection, and whether the use of 

fracturing for the purposes of well stimulation is appropriate. 

NYSDEC-DMN Response: Hydraulic fracturing of wells in New York may be necessary 

in some cases to complete or recomplete an injection well. Any fracturing during 

well completion stimulation should be engineered so as to eliminate any risk of 

damage to confining zone(s). Other stimulation techniques should also be allowed 

provided there is no endangerment to USDWs. In addition, NYSDEC-DMN agrees with 

Response: The final GS regulation allows hydraulic fracturing only during Class VI well

stimulation. Section 146.88(a) permits injection pressure to exceed 90 percent of the fracture pressure

only during well stimulation. EPA acknowledges that in some circumstances hydraulic fracturing

during a well workover may be appropriate. The final rule at §146.91(d)(2) includes a requirement

that the owner or operator notify the Director 30 days before performing stimulation during the

operational phase of a GS project; this will provide an additional opportunity for the 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 in order to protect USDWs from endangerment.
Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25192

Comment: T. EPA is also requesting information to better qualify the use of fracturing 

for GS injection in specific geologic settings and rock formation lithologies. 

NYSDEC-DMN Response: As indicated above, engineered hydraulic fracturing of the 

injection zone should only be allowed during the initial completion or 

recompletion of a well. 

Response: The final GS regulation allows hydraulic fracturing only during Class VI well

stimulation. Section 146.88(a) permits injection pressure to exceed 90 percent of the fracture pressure

only during well stimulation. EPA acknowledges that in some circumstances hydraulic fracturing

during a well workover may be appropriate. The final rule at §146.91(d)(2) includes a requirement

that the owner or operator notify the Director 30 days before performing stimulation during the

operational phase of a GS project; this will provide an additional opportunity for the 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24527

Comment: Rule Provisions or Federal Register Cite: 146.88(a) 

EPA Preamble Question: 20. EPA is requesting comment on the extent to which 

hydraulic fracturing should be allowed during GS injection, and whether the use 

of fracturing for the purposes of well stimulation is appropriate. EPA Notice 

43511. 

CSC Response: The use of fracturing for stimulation is appropriate and should be 

allowed provided that there is no damage to the confining unit that would result 

in endangerment of USDWs. There are computer simulators to predict fracture 

behavior so the impact on the confining zone can be anticipated. 

Response: EPA agrees that stimulation, such as hydraulic fracturing, should be permitted in some

situations, and the final rule allows the use of hydraulic fracturing at GS sites where approved by the

Director. Hydraulic fracturing is one of several stimulation technologies available to improve

wellbore and formation injectivity. EPA clarifies that fracturing is permitted during stimulation, but

not during injection. During injection, the injection pressure must not exceed 90 percent of the

fracture pressure, as specified in §146.88(a).

All stimulation, including hydraulic fracturing, must be approved by the Director. Owners or

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

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

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

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

perform stimulation only as approved. It is possible that computer simulations may support this

determination to the Director's satisfaction. EPA clarifies that all data submitted with the permit

application, including modeling of the AoR, will inform the Director's decision on whether hydraulic

fracturing is acceptable at a GS site.
Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24590

Comment: Rule Provisions: 146.88(a) 

EPA Rule Issue: 20. EPA is requesting comment on the extent and scope to which 

hydraulic fracturing should be allowed during GS injection, and whether the use 

of fracturing for the purposes of well stimulation is appropriate. EPA Notice 

43511. 

Anadarko Petroleum Corporation (APC) Response: The use of fracturing for 

stimulation should be allowed provided that there is no damage to the confining 

unit that would result in endangerment of USDWs. Industry has demonstrated the 

ability to fracture injection zones without jeopardizing the integrity of the 

confining unit. There are computer simulators to predict fracture behavior so 

the impact on the confining zone can be anticipated and accounted for in 

designing any proposed operations involving fracturing. 

Response: EPA agrees that hydraulic fracturing may be appropriate in some situations, and the final

rule allows the use of hydraulic fracturing at GS sites, where approved by the Director. Hydraulic

fracturing is one of several stimulation technologies available to improve wellbore and formation

injectivity. EPA clarifies that fracturing is permitted during stimulation, but not during injection.

During injection, the injection pressure must not exceed 90 percent of the fracture pressure, as

specified in §146.88(a).

All stimulation, including hydraulic fracturing, must be approved by the Director. Owners or

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

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

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

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

perform stimulation only as approved. It is possible that computer simulations may support this

determination to the Director's satisfaction. EPA clarifies that all data submitted with the permit

application, including modeling of the AoR, will inform the Director's decision on whether hydraulic

fracturing is acceptable at a GS site.

Commenter Name: Richard Guinn Letter ID: 0210

Commenter Organization: Eastman Chemical Company Comment ID: 22733

Other EPA Comment Codes and Descriptions: 4120 2.4.1.2 Allowing hydraulic fracturing during

GS (seeking comment) 

Comment: EPA is requesting comment on the extent and scope to which hydraulic fracturing 

should be allowed during GS injection, and whether the use of fracturing for the 

purposes of well stimulation is appropriate. EPA Notice 85. 

Fracturing of GS formations should be permitted, provided confining structures 

are not negatively impacted and fracturing is limited to the injection zone. 

Exclusion of fracturing of storage formations would often require unnecessary 

drilling of new injection wells. The oil industry has sufficient experience in 

using fracturing technology to avoid negatively impacting confining structures 

(e.g., caprock). 
Response: EPA recognizes that there may be well completions which require intermittent treatments

that include stimulation to improve wellbore injectivity. Stimulation of the injection zone during a

well workover will be permissible, if approved by the Director (operators seeking to use stimulation

must submit the proposed stimulation program as part of the permit application under §146.82(a)(9)

where injection pressure limits will be set). EPA has also added a requirement that owners or

operators notify the Director in advance of any planned stimulation activities, as specified at

§146.91(d). During injection, the injection pressure must not exceed 90 percent of the fracture

pressure, as specified in §146.88(a). EPA clarifies that the injection pressure limit at §146.88(a)

applies only to the period of injection, not well stimulation.

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21684

Other EPA Comment Codes and Descriptions: 4000 2.4 Proposed Injection Well Operating

Requirements (40 CFR 146.88) 

Comment: number of penetrations through the caprock. There are other options to optimize 

injectivity as well that include, but should not be limited to, hydraulic 

fracture treatments, multiple injection points along the wellbore and open hole 

completions. 

Response: EPA agrees that hydraulic fracturing is one of several stimulation technologies available

to improve wellbore and formation injectivity. The final rule allows the use of hydraulic fracturing at

GS sites, if approved by the Director. 

EPA clarifies that all stimulation for Class VI wells, including hydraulic fracturing, must be

approved by the Director. Owners or operators must submit a proposed stimulation program as part

of the permit application under §146.82(a)(9); the plan must demonstrate that any stimulation

activities will not compromise the integrity of the confining zone. The Director will evaluate the

owner or operator's proposed stimulation plan in the context of all information about the site, and the

owner or operator must perform stimulation only as approved. 

The final rule also requires that the owner or operator notify the Director 30 days before performing

stimulation during injection operations (§146.91(d)(2)); this will provide an additional opportunity

for the 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.

EPA also agrees that multiple and open hole completions are also acceptable manners to improve

injectivity. Class VI wells with these types of completions are acceptable, provided all other

construction requirements at §146.86 are met.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21735

Other EPA Comment Codes and Descriptions: 4000 2.4 Proposed Injection Well Operating

Requirements (40 CFR 146.88) 

Comment: limits the number of penetrations through the caprock. There are other options 

to optimize injectivity as well that include, but should not be limited to, 

hydraulic fracture treatments, multiple injection points along the wellbore and 

open hole completions. 
Response: EPA agrees that hydraulic fracturing is one of several stimulation technologies available

to improve wellbore and formation injectivity. The final rule allows the use of hydraulic fracturing at

GS sites, if approved by the Director. 

EPA clarifies that all stimulation of Class VI wells, including hydraulic fracturing, must be approved

by the Director. Owners or operators must submit a proposed stimulation program as part of the

permit application under §146.82(a)(9); the plan must demonstrate that any stimulation activities will

not compromise the integrity of the confining zone. The Director will evaluate the owner or

operator's proposed stimulation plan in the context of all information about the site, and the owner or

operator must perform stimulation only as approved. 

The final rule also requires that the owner or operator notify the Director 30 days before performing

stimulation during injection operations (§146.91(d)(2)); this will provide an additional opportunity

for the 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.

EPA also agrees that multiple and open hole completions are also acceptable manners to improve

injectivity. Class VI wells with these types of completions are acceptable, provided all other

construction requirements at §146.86 are met.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23242

Other EPA Comment Codes and Descriptions: 4120 2.4.1.2 Allowing hydraulic fracturing during

GS (seeking comment) 

Comment: 20. EPA is requesting comment on the extent and scope to which hydraulic 

fracturing should be allowed during GS injection and whether the use of 

fracturing for the purposes of well stimulation is appropriate. EPA Notice 

43511. 

Hydraulic fracturing should be allowed as long as it does not compromise the 

confining zone. Computer modeling to predict the fracture growth can be 

utilized in fracture stimulation design. 

Response: EPA agrees that stimulation, such as hydraulic fracturing should be permitted in some

situations, and the final rule allows the use of hydraulic fracturing at GS sites, where approved by

the Director. Hydraulic fracturing is one of several stimulation technologies available to improve

wellbore and formation injectivity. EPA clarifies that fracturing is permitted during stimulation, but

not during injection. During injection, the injection pressure must not exceed 90 percent of the

fracture pressure, as specified in §146.88(a).

All stimulation, including hydraulic fracturing, must be approved by the Director. Owners or

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

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

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

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

perform stimulation only as approved. It is possible that computer simulations may support this

determination to the Director's satisfaction. EPA clarifies that all data submitted with the permit
application, including modeling of the AoR, will inform the Director's decision on whether hydraulic

fracturing is acceptable at a GS site.

Letter ID: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22806

Other EPA Comment Codes and Descriptions: 4120 2.4.1.2 Allowing hydraulic fracturing during

GS (seeking comment) 

Comment: III A. 4 Proposed Injection Well Operating Requirements 

U. EPA is requesting comment on the extent and scope to which hydraulic fracturing 

should be allowed during GS injection, and whether the use of fracturing for the 

purposes of well stimulation is appropriate. 

IOGCC Response: While hydraulic fracturing maybe necessary in some cases to 

complete an injection well, it should not be allowed during GS injection. 

Any fracturing during well completion stimulation should be engineered so as to 

eliminate any risk of damage to confining zones. 

Response: EPA emphasizes that fracturing of the confining zone during injection and/or stimulation

is prohibited, as specified at §146.88(a). However, EPA believes there are some circumstances where

fracturing of the injection zone may be acceptable, provided the integrity of the confining system

remains unaffected and maintains USDW protection. EPA clarifies that §146.88(a) permits injection

pressure to exceed 90 percent of the fracture pressure only during well stimulation. The final rule

allows the use of hydraulic fracturing at GS sites, where approved by the Director. Hydraulic

fracturing is one of several stimulation technologies available to improve wellbore and formation

injectivity. 

EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director.

Owners or operators must submit a proposed stimulation program as part of the permit application

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

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

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

perform stimulation only as approved. 

The final rule at §146.91(d)(2) also requires that the owner or operator notify the Director 30 days

before performing stimulation during the operational phase of a GS project; this will provide an

additional opportunity for the Director to review the owner or operator's plans for stimulation and

add other requirements as needed.

Comment Code: 4140 2.4.1.4 Use of fracturing for GS in specific geologic settings (seeking

comment) 

Individual Comments

Commenter Name: Pamela A. Lacey Letter ID: 0228

Commenter Organization: American Gas Association Comment ID: 21804
Other EPA Comment Codes and Descriptions: 3800 2.3 Proposed Injection Well Construction

Requirements (40 CFR 146.86) 

Comment: - Require Analysis before Hydraulic Fracturing for GS Wells Near Gas Storage: 

Before hydraulic fracturing of a GS injection well, the GS operator should 

perform an analysis to consider the proximity, both laterally and vertically, of 

the GS zone to existing natural gas storage reservoirs, and should analyze the 

fracturing design to examine the potential for communication with a natural gas 

storage reservoir. This could be added to the injection well construction 

requirements in section 146.86. 

Response: EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the

Director. Owners or operators must submit a proposed stimulation program as part of the permit

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

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

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

must perform stimulation only as approved. 

The final rule also requires that the owner or operator notify the Director 30 days before performing

stimulation during injection operations (§146.91(d)(2)); this will provide an additional opportunity

for the 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.

EPA believes that the extensive requirements for geologic site characterization (at §146.82), AoR

evaluation (§146.84), and testing of the well during drilling (§146.87) are appropriate to ensure that

permitting authorities have the necessary information to evaluate whether a specific site will allow

safe injection of CO2. EPA believes that any natural gas storage operations will be identified during

site characterization pursuant to requirements at §146.82 and §146.83 as will any faults or fractures. 

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23243

Comment: 21. EPA is also requesting information to better qualify the use of fracturing 

for GS injection in specific geologic settings and rock formation lithologies. 

EPA Notice 43511. 

This type of information needs to be obtained from industry. Many basins have 

implemented hydraulic fracturing of certain formations for a number of years. 

These situations are best handled locally where the regional geologic factors 

can be considered. 

Response: EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the

Director based on site-specific information. Owners or operators must submit a proposed stimulation

program as part of the permit application under §146.82(a)(9); the plan must demonstrate that any

stimulation activities will not compromise the integrity of the confining zone. The Director will

evaluate the owner or operator's proposed stimulation plan in the context of all information about the

site, and the owner or operator must perform stimulation only as approved. 

The final rule at §146.91(d)(2) also requires that the owner or operator notify the Director 30 days

before performing stimulation during the operational phase of a GS project; this will provide an
additional opportunity for the 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: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22807

Comment: III A. 4 Proposed Injection Well Operating Requirements 

V. EPA is also requesting information to better qualify the use of fracturing for 

GS injection in specific geologic settings and rock formation lithologies. 

IOGCC Response: As indicated above, hydraulic fracturing should only be allowed 

during the initial completion or recompletion of a well to enhance reservoir 

permeability. However, once the completion phase has ended and the operational or 

injection phase has begun, fracturing during injection should never be 

permitted. It is important to keep separate the concept of operational injection 

pressure limits and episodic well stimulation activities. 

In this respect, there should be no injection above the allowable permitted 

pressure. Additionally, hydraulic fracturing of the caprock should never be 

allowed nor should pressure testing of the confining layer. 

Response: As described above, the final GS regulation allows hydraulic fracturing only during Class

VI well stimulation, as specified at §146.88(a). EPA acknowledges that in some circumstances

hydraulic fracturing during a well workover may be appropriate. The final rule at §146.91(d)(2)

includes a requirement that the owner or operator notify the Director 30 days before performing

stimulation during the operational phase of a GS project; this will provide an additional opportunity

for the 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 in order to protect USDWs from endangerment.

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

Individual Comments

Commenter Name: Brian Williams Letter ID: 0116

Commenter Organization: BP Alternative Energy Comment ID: 22055

Comment: Standard requirement for downhole shut-in devices -- BP disagrees with the rule 

to include downhole shut-in devices as a standard requirement for injection 

wells. Overpressure protection is best achieved by ensuring compatibility of the 

casing/tubing material design strength with the surface injection (compression) 

system. Downhole shut-in devices may be appropriate, however, for site-specific 

situations of unique potential impact (such as offshore or near airports), but 

they should not be mandated for all injection sites. 

Response: EPA agrees that proper design of the well, including appropriate materials and
emplacement of casing and tubing, is essential to proper operation of the well. Such design,

however, does not eliminate the possibility of failure, e.g., due to over-pressurization as suggested

by the commenter. EPA believes that a multiple-barrier approach, which includes appropriate well

design as required at §146.86, suitable injection pressure limits as required at §146.88(a), and

automatic shut-off systems, as required at §146.88(e), is necessary to ensure protection of USDWs

from endangerment from the risks associated with CO2 GS.

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. However, 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.

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24737

Comment: equally as stringent as the Class I hazardous waste well requirements. - Annulus 

liquid level indicator and a down-hole shut-off valve are not required for a 

Class I hazardous waste injection well. 

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. However, the

Agency believes 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.

Regarding annulus fluid volume, EPA believes that knowing annulus fluid volume, as required at

§146.88(e), is a necessary component of monitoring well mechanical integrity, but believes that

monitoring the annulus fluid volume added is sufficient to meet the intent of continuous monitoring

of the pressure on the annulus. The final GS rule at §146.90 (b), requires that owners or operators

use continuous recording devices to monitor injection pressure, rate and volume; the pressure on the

annulus between the tubing and the long string casing; and the annulus fluid volume added.

Commenter Name: Leslie Savage Letter ID: 0122
Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24750

Comment: testing and reporting. For example, 

a. revisit the requirement for an need annulus liquid level indicator; 

b. delete the requierment for the down hole shut off valve; 

Response: EPA believes that knowing annulus fluid volume, as required at §146.88(e), is a

necessary component of monitoring well mechanical integrity, but believes that monitoring the

annulus fluid volume added is sufficient to meet the intent of continuous monitoring of the pressure

on the annulus. The final GS rule at §146.90 (b), requires that owners or operators use continuous

recording devices to monitor injection pressure, rate and volume; the pressure on the annulus

between the tubing and the long string casing; and the annulus fluid volume added. 

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. However, the Agency

believes 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.

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24791

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: (e) The owner or operator must install and use continuous recording devices to 

monitor: The injection pressure; the rate, volume, and temperature of the 

carbon dioxide stream; and the pressure on the annulus between the tubing and 

the long string casing and annulus fluid volume; and must install and use alarms 

and automatic down-hole shut-off systems, designed to alert the operator and 

shut-in the well when operating parameters such as annulus pressure, injection 

rate or other parameters approved by the Director diverge beyond permitted 

ranges and/or gradients specified in the permit; 

{RRC suggests that the rule not require automatic shutdown. Experience in the 

field has been that ESDs are notorious for high maintenance, and continuous 

monitoring will sufficiently alert the operator of a need to shut down 

operations. In addition, such a requirement is more stringent than that 

required for Class I hazardous waste wells.} 

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 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 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, which may endanger

USDWs. 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). Additionally, the Agency believes 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. Automatic shut-off devices can help prevent further well

complications, and EPA believes affording Director's discretion to require down-hole devices where

necessary ensures that proper precautions are taken to prevent subsurface fluid movement and ensure

protection of USDWs, human health, and the environment.

EPA believes that requiring automatic surface shut-off devices instead of down-hole devices

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.

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24792

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: (f) If a down-hole automatic shutdown is triggered or a loss of mechanical 

integrity is discovered, the owner or operator must immediately investigate and 

identify as expeditiously as possible the cause of the shutoff. If, upon 

such investigation, the well appears to be lacking mechanical integrity, or if 

monitoring required under paragraph (e) of this section otherwise indicates that 

the well may be lacking mechanical integrity, the owner or operator must: 

Response: As described above, 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), affords Director's discretion to mandate

automatic down-hole shut-off devices in onshore situations that may warrant their use. However, the

Agency believes 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.
Commenter Name: John Stormon Letter ID: 0123

Commenter Organization: Washington State Dept. of Ecology Comment ID: 23004

Comment: Downhole valves and other required downhole equipment may impact or prevent 

certain monitoring techniques. It is important to require appropriate safeguards 

but establishing prescriptive safeguards may be counterproductive and are likely 

to prevent the use of cutting edge technologies as new methods are developed. 

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. However, the

Agency believes 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.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141

Commenter Organization: Global Energy, Inc. Comment ID: 23096

Comment: readily managed with current technologies. EPA proposals for surface and downhole shutoffs are reasonable additions to mechanical designs. 

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. However, the

Agency believes 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.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141

Commenter Organization: Global Energy, Inc. Comment ID: 23112

Comment: method. Appropriate instrumentation and shut-offs are reasonable. 

Response: As described above, 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.

However, the Agency believes 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 requiring the installation of automatic surface shut-off devices for onshore wells

(and affording Director's discretion to require down-hole devices where necessary) ensures that

proper precautions are taken to prevent subsurface fluid movement and ensure protection of USDWs,

human health, and the environment.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141

Commenter Organization: Global Energy, Inc. Comment ID: 23119

Comment: 5.Automatic shutoff down hole, in addition to surface shut off, is appropriate. 

Response: As described above, 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.

However, the Agency believes 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.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22558

Comment: For both types of wells, it is important that regulations require that internal 

safety measures are installed in the well. This will help ensure that wells do 

not allow leakage out of the well through the wellbore in the case of an 

accident or other event. Down-hole shutoff equipment needs to be required. The 

shutoff equipment needs to be downhole to avoid leakage if the surface 

components of the well are damaged. 

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. However, the

Agency believes 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.

Commenter Name: Patrick Nugent Letter ID: 0143

Commenter Organization: Texas Pipeline Association (TPA) Comment ID: 23137

Comment: 4. Down-hole automatic shut-off devices should not be required in all 

cases. TPA disagrees with the proposed requirement of down-hole automatic shutoff devices. This requirement is not imposed upon wells in other classes and 

there is no reason why such a requirement should be placed, on an across-theboard basis, upon Class VI wells. Such a requirement would impose an unnecessary 

expense in many cases. At most, such a requirement should only be imposed on a 

site-specific, case-by-case basis. 

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. However, the

Agency believes 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 clarifies that down-hole shut-off devices are currently used in situations where loss of well

integrity could result in damage to the well or harm to humans (e.g., near high-density population

areas, or in onshore acid gas injection; IEA, 2003). EPA has identified examples of documented

logging techniques, including ultrasonic and temperature logs, that can be performed with an

automatic down-hole device emplaced (Julian et al., 2007; Somaschini et al., 2009). They are also

used in high pressure, high temperature onshore wells and in permafrost areas.

Commenter Name: Brianne Metzger Letter ID: 0151

Commenter Organization: Spectra Energy Corp Comment ID: 21839

Comment: G. The Use Of Down-Hole Devices And Coupons Should Be Limited. 

Although we do not believe that downhole monitoring devices are necessary for 

GS wells, the use of emergency shutdown devices (ESDs) may be important. At 

our Kwoen facility where we inject a sour CO2 mixture that is 80% H2S and 20% 

CO2, we use primarily three forms of ESD: (1) a valve at the wellhead, (2) a 

subsurface safety valve, and (3) a check valve at the packer. This ESD 

configuration enables us to plan for and respond to a number of contingencies, 

including (1) shutting down the wellhead (2) shutting the subsurface safety 

valve in the event the wellhead is sheared off or damaged, which prevents 

atmospheric leaks and (3) closing the packer check valve, which enables us to 

conduct any uphole work. For gas storage involving only the injection of sweet 

gas, typically only wellhead ESD is used. 
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. However, the

Agency believes 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.

Commenter Name: Bonnie Lovelace Letter ID: 0152

Commenter Organization: Montana Department of Environmental Quality

(MDEQ)

Comment ID:

22115

Comment: 14. EPA seeks comment on the merits of requiring down-hole shut off valves in 

geologic sequestration wells. MDEQ agrees with the EPA approach to this safety 

consideration. Public health and safety issues suggest that in the case 

of leakage or malfunction this is a reasonable mitigation to overcome surface 

shut off problems. 

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. However, the

Agency believes 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.

Commenter Name: James Dooley Letter ID: 0156

Commenter Organization: Joint Global Change Research Institute, Pacific

Northwest National Laboratory

Comment ID:

22661

Comment: - Page 43511. The USEPA does a good job of explaining why the cost of requiring 

down hole shut off valves should not be seen as being overly burdensome for 

potential operators of GS sites. While the logic and data presented here seem 

convincing and make the point, it seems that a cost/benefit calculation might be 

a secondary issue. If the USEPA believes that these down hole shut off valves 

are needed to discharge its responsibilities under the SDWA (i.e., protect 

USDWs) then that should be the primary reason. The USEPA should not need to 
defend requirements needed to carry out its responsibilities under the SDWA with 

cost/benefit analyses. 

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. However, the

Agency believes 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 clarifies that the decision not to require the use of down-hole shut-off systems for all onshore

wells was not based on the cost of such systems, but the effect such systems would have on well

operation and whether it was necessary to protect USDWs from endangerment in all cases.

Commenter Name: Michael Mudd Letter ID: 0167

Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 22469

Comment: The use of down-hole shut-off valves that would automatically shut-in the well 

is recommended as a possible safety device in CO2 injection wells. This 

reviewer recently contacted the vendor cited by EPA (Schlumberger) for 

information on safety valves for a CO2 injection well and was told that they 

are not available in sizes that would be needed for most on-shore injection 

wells because these devices are primarily used in larger off-shore wells. The 

use of safety valves needs more consideration. 

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 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.

While EPA acknowledges that the likelihood of damage to onshore facilities is lower than that for

offshore facilities, down-hole shut-off valves are still commonly used in onshore facilities such as

acid gas injection wells and high pressure, high-temperature wells. However, the Agency believes

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. While valve failure is a

concern, EPA believes that technology has advanced sufficiently to make valve failure a rare
occurrence and to appropriately handle such failure if it occurs. For example, wireline retrievable

devices can allow repair or replacement of damaged devices without necessitating pulling the tubing.

EPA believes that, while the smaller valve sizes needed for onshore injection wells may not be as

common, these devices have been installed in other similar projects and therefore should be

available. Acid gas injection wells commonly use down-hole shut-off valves (IEA Greenhouse Gas

Research Program, 2003; Bachu and Gunter, 2003).

Commenter Name: Michael Mudd Letter ID: 0167

Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 22470

Comment: A-5 Mechanical Integrity Testing Requirements III-A-5 Automated down-hole shut 

valves sound problematic, especially if they are intended to respond to 

excursions in annular pressure and volume which are subject to temperature 

fluctuations. See above comment. 

Response: As described above, 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

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 requiring the installation of automatic surface shut-off devices for onshore wells

(and affording Director's discretion to require down-hole devices where necessary) and automatic

down-hole shut-off devices for offshore wells in submerged lands within the jurisdiction of a State

ensures that proper precautions are taken to prevent subsurface fluid movement and ensure protection

of USDWs.

Commenter Name: Michael J. Miller Letter ID: 0168

Commenter Organization: Electric Power Research Institute (EPRI) Comment ID: 22504

Comment: Preamble, page 43511: "In case of well failure, a down-hole shut-off device 

would isolate the injectate below USDWs, rather than just below the surface. EPA 

seeks comment on the merits of requiring down-hole shut-off valves in GS wells." 

EPRI COMMENT #10: Since a downhole shut-off valve would just prevent CO2 from 

flowing from the injection zone up the production tubing to the atmosphere if 

the wellhead were damaged, it doesn’t serve a function in protecting USDWs. 

Further, because, recorded cases of catastrophic wellhead failure are rare, and 

the valve would not protect CO2 from backflowing to the surface should the 

packer also fail, EPRI does not believe that a down-hole shut-off valve provides 

more safety than an easier-to-maintain near-surface shut-off valve. In addition, 

a downhole valve will interfere with logging operations, mechanical integrity 

testing, video inspection logs, etc. Downhole tools typically associated with 

these activities are deployed by wireline inside the production tubing, 

requiring that the operator needlessly kill the well, and remove the tubing and 

valve to gain access to the section of well below the valve position. 
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. However, the

Agency believes 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 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.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24119

Other EPA Comment Codes and Descriptions: 1210 1.1.1 Comments about the proposed rule 

Comment: API offers many technical clarifications to the rule based on industry's 

experience with well design, construction, and operation. Some are minor 

clarifications but others are important revisions. For example, EPA is proposing 

the use of down-hole shut-off valves (see proposed §146.88(e) at 73 FR 43539), 

saying they would "isolate the injectate below USDWs, rather than just below the 

surface" (73 FR 43511) when in fact, down-hole shut-off valves would not 

actually address this concern since they are not designed to provide the type of 

isolation envisioned by the EPA. 

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. However, the

Agency believes 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 clarifies that down-hole shut-off devices are currently used in situations where loss of well

integrity could result in damage to the well or harm to humans (e.g., near high-density population

areas, or in onshore acid gas injection; IEA, 2003). EPA has identified examples of documented
logging techniques, including ultrasonic and temperature logs, that can be performed with an

automatic down-hole device emplaced (Julian et al., 2007; Somaschini et al., 2009). They are also

used in high pressure, high temperature onshore wells and in permafrost areas.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24126

Comment: Furthermore, some of the proposed requirements - such as cementing the long 

string casing to surface and use of down-hole shut-off valves - are not only 

unnecessarily burdensome, but might also interfere with operations, may not 

serve their intended purpose, and could introduce unintended risks. For example, 

Response: As described above, 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

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.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24183

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(e) 

API Comments: (e) The owner or operator must install and use continuous 

recording devices to monitor: the injection pressure; the rate, volume, and 

temperature of the carbon dioxide stream and. THE OWNER OR OPERATOR MUST 

REGULARLY MONITOR the pressure on the annulus between the tubing and the long 

string casing and annulus fluid volume and. THE OWNER OR OPERATOR must 

install and use alarms and automatic down-hole shut-off systems, designed to 

alert the operator and shutin the well when operating parameters such as 

injection rate, injection pressure, or other parameters approved by the Director 

diverge beyond ranges and/or gradients specified in the permit; 

Rationale: Over-pressure protection is best achieved by ensuring 

compatibility of the casing/tubing material design strength with the surface 

injection (compression) system. Down-hole shut-in devices are not appropriate 

for this application. These devises are installed in the tubing string and are 

typically near the surface of the well. They‘re intended to seal the tubing in 

the event of catastrophic failure of the wellhead. These devises would provide 

little if any protection to USDWs. Is not practicable to install these devises 

deep within the well (e.g. shortly above the packer). Additionally these devises 

create a restriction on running other tools like logging tools in the well and 

therefore could limit an operators ability to do required monitoring and 

diagnostic work. Lastly, these devises require periodic testing and maintenance 

which could require either pulling the device by wireline or by pulling the 

entire tubing string depending on the type of device installed. Either of these 
activities would be disruptive and costly to the overall project operations. 

A more appropriate approach would be installation of landing nipples at 

appropriate points in the tubing string which would allow use of wireline 

retrievable plugs when needed. 

Response: EPA acknowledges that proper design of the well, including appropriate materials and

emplacement of casing and tubing, is essential to proper operation of Class VI wells. Such design,

however, does not eliminate the possibility of failure, e.g., due to over-pressurization as suggested

by the commenter. EPA believes that a multiple-barrier approach, which includes appropriate well

design as required at §146.86, suitable injection pressure limits as required at §146.88(a), and

automatic shut-off systems, as required at §146.88(e), is necessary to ensure protection of USDWs

from endangerment from the risks associated with CO2 GS.

Landing nipples, which are machined portions of the tubing that allow the seating of components–

such as safety valves—at a later time, can be used to deploy safety valves after the initial well

completion. EPA believes, however, that if the shut-off system is not deployed until the failure

occurs, CO2 will be free to flow out of the well until the shut-off valve is deployed. Since installing

the new shut-off system will require getting the device to the site, setting up a rig, and deploying the

device down the well, a significant amount of time could elapse following an adverse event before

the well is sealed. EPA believes that the risks of uncontrolled CO2 flow are too great to be allowed

for such a length of time. 

As described above, 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 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.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24184

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(f) 

API Comments: (f) If aN down-hole automatic shutdown is triggered or a loss 

of mechanical integrity is discovered, the owner or operator must immediately 

investigate and identify as expeditiously as possible the cause of the 

shutoff. If, upon such investigation, the well appears to be lacking 

mechanical integrity, or if monitoring required under paragraph (e) of this 

section otherwise indicates that the well may be lacking mechanical integrity, 

the owner or operator must: 

Rationale: Technical clarification given changes above. 
Response: As described above, 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

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. Please see the final rule and preamble for

additional information on EPA's final approach.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24237

Comment: Rule Provisions: 146.88(e) 

EPA Preamble Question: 22. EPA seeks comment on the merits of requiring downhole shut-off valves in GS wells. EPA Notice 43511. 

API Response: Over-pressure protection is best achieved by ensuring 

compatibility of the casing/tubing material design strength with the surface 

injection (compression) system. Down-hole shut-in devices are not appropriate 

for this application. These devises are installed in the tubing string and are 

typically near the surface of the well. They’re intended to seal the tubing in 

the event of catastrophic failure of the wellhead. These devises would provide 

little if any protection to USDWs. Is not practicable to install these devises 

deep within the well (e.g. shortly above the packer). Additionally these devises 

create a restriction on running other tools like logging tools in the well and 

therefore could limit an operators ability to do required monitoring and 

diagnostic work. Lastly, these devises require periodic testing and maintenance 

which could require either pulling the devise by wireline or by pulling the 

entire tubing string depending on the type of devise installed. Either of these 

activities would be disruptive and costly to the overall project operations. 

A more appropriate approach would be installation of landing nipples at 

appropriate points in the tubing string which would allow use of wireline 

retrievable plugs when needed. 

Response: As described above, 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 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.

Commenter Name: James Rower Letter ID: 0173

Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23493

Comment: 10. Proposed Injection Well Operating Requirements 

USWAG reiterates that in order to accommodate developing technology and varied 

geological settings, the Final Rule must be flexible and avoid overly burdensome 

or prescriptive measures that do little to further the protection of USDWs. For 

example, a requirement for down-hole shut-off valves would force Owners or 
Operators to incur great costs, particularly if those valves malfunction, with 

minimal benefit. Id. at 43511. 

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. However, the

Agency believes 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 clarifies that down-hole shut-off devices are currently used in situations where loss of well

integrity could result in damage to the well or harm to humans (e.g., near high-density population

areas, or in onshore acid gas injection; IEA, 2003). EPA has identified examples of documented

logging techniques, including ultrasonic and temperature logs, that can be performed with an

automatic down-hole device emplaced (Julian et al., 2007; Somaschini et al., 2009). They are also

used in high pressure, high temperature onshore wells and in permafrost areas.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23862

Comment: annular fluid. EPA also recommends as a possible safety device in CO2 injection 

wells the use of down-hole shut-off valves that would automatically shut-in the 

well. It is not clear that safety valves for a CO2 injection wells are available 

in the sizes necessary for most on-shore injection wells because these devices 

are primarily used in larger, off-shore wells. The use of such valves, 

therefore, needs more consideration. 

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. However, the

Agency believes 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.

Commenter Name: Robert J. Finley Letter ID: 0180
Commenter Organization: Illinois State Geological Survey Comment ID: 23637

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 

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. 

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.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23685

Other EPA Comment Codes and Descriptions: 2060 1.5.3 Comments on grandfathering of

existing wells (seeking comment) 

Comment: AWWA Response: Grandfathered wells may not have some of the protective measures 

that are required in the proposed regulation, such as the down-hole shut-off 

valve. This valve is an important safety mechanism and AWWA believes that a 

Class VI well should not be permitted for carbon sequestration unless it is 

constructed with this appurtenance. Also, some of the potentially grandfathered 

Response: EPA believes that some wells can be re-permitted for use as Class VI wells and safely

operated, even if down-hole shut-off systems cannot be installed. 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. However, the Agency believes 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. 

The final GS regulation requires at §146.81(c) that owners or operators seeking to grandfather

existing Class I, II, or V wells for GS demonstrate that grandfathered wells were engineered and

constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of

requirements at §§146.86(b) and 146.87(a). In addition, these grandfathered wells would still be

required to meet the other requirements of the GS regulation (e.g., operating, monitoring, MIT, well

plugging, and post-injection site care and site closure requirements).

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23694

Other EPA Comment Codes and Descriptions: 3862 2.3.3.1 Use of corrosion-resistant

construction materials (seeking comment) 

Comment: Group: Well Construction 

EPA Request for Comment: EPA seeks comment regarding requirements for 

degradation-resistant well construction materials, such as acid-resistant 

cements and corrosion resistant casing. EPA Notice 43510. 

EPA seeks comment on the merits of requiring down-hole shut-off valves in GS 
wells. EPA Notice 43511. 

AWWA Response: AWWA recommends that injection wells be constructed from 

degradation-resistant materials to prevent carbon dioxide from escaping from a 

portion of the injection well that may have been compromised due to noncompatible materials. AWWA also recommends that down-hole shut-off valves be 

required for all injection wells. These valves can be a first line of defense 

against contamination of USDWs due to faulty injection practices. Further 

research is needed by both EPA and DOE to identify specific construction methods 

that would prevent degradation of the well and the carbon sequestration site. 

AWWA recommends the creation of a certification program that would be used to 

guarantee that existing or newly developed construction methods are approved for 

use with geologic sequestration. 

Response: EPA agrees that the use of non-compatible materials can result in degradation and failure

of the well and could ultimately endanger a USDW. Under §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. 

EPA disagrees that the rule should contain a construction method certification program. EPA

believes that the prescribed construction requirements for Class VI wells are sufficient to protect

USDWs from endangerment. EPA adds that the requirement at §146.86(b)(1) that materials must

meet or exceed standards developed by the American Petroleum Institute, ASTM International, or

comparable standards acceptable to the Director invokes the expertise of these bodies without the

added burden of a certification program. 

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.

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 such devices are 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 Directors discretion to mandate automatic

down-hole shut-off devices in onshore situations that may warrant their use. However, the Agency

believes 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.

Commenter Name: Bradley J. Field Letter ID: 0186
Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25193

Comment: U. EPA seeks comment on the merits of requiring down-hole shut-off valves in GS 

wells. 

NYSDEC-DMN Response: Downhole shut-off valves, sometimes referred to as surfacecontrolled subsurface safety valves (SCSSV), should not be mandated in GS wells 

without further assessing the risk of wells without such (i.e., failure rate) 

and possible maintenance problems. It is NYSDEC-DMN’s understanding that SCSSVs 

are used in the offshore oil and gas industry primarily due to risks associated 

with maritime collision and hurricane events (i.e., ability to shut wells in 

downhole before platform evacuation). SCSSV are also part of an offshore 

facility’s emergency shutdown system. Nevertheless, at Director discretion, 

SCSSVs may provide an extra level of protection in sensitive settings but should 

not be required for all projects without additional study. 

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. 

While EPA acknowledges that the likelihood of damage to onshore facilities is lower than that for

off-shore facilities, down-hole shut-off valves are still commonly used in onshore facilities such as

acid gas injection wells and high pressure, high-temperature wells. While valve failure is a concern,

EPA believes that technology has advanced sufficiently to make valve failure a rare occurrence and

to appropriately handle such failure if it occurs. For example, wireline retrievable devices can allow

repair or replacement of damaged devices without necessitating pulling the tubing.

EPA believes that requiring the installation of automatic surface shut-off devices for onshore wells

(and affording Director's discretion to require down-hole devices where necessary) and automatic

down-hole shut-off devices for offshore wells in submerged lands within the jurisdiction of a State

ensures that proper precautions are taken to prevent subsurface fluid movement and ensure protection

of USDWs.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25199

Other EPA Comment Codes and Descriptions: 4520 2.5.1 Continuous internal mechanical

integrity monitoring (seeking comment) 

Comment: III A. 5 Proposed Mechanical Integrity Testing Requirements 

AA. EPA requests comment on the practicability of this requirement. 
NYSDEC-DMN Response: NYSDEC-DMN supports EPA’s proposal to require operators of 

GS projects to monitor internal mechanical integrity by continuously monitoring 

injection pressure, flow rate, and injected volumes, as well as annular pressure 

and fluid volume to provide early detection of anomalies that may indicate an 

internal leak. However, an "alarm" should shut in the well at the surface rather 

than requiring the installation and use of a downhole shut-off valve. 

Response: EPA acknowledges the comment and believes that continuous pressure monitoring to

demonstrate internal mechanical integrity of Class VI wells required at §146.89(b), instead of

periodic testing, which is required for most other types of deep injection wells is important given the

potential corrosive impact of CO2 and impurities on well materials, the potential geomechanical

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

associated with injecting supercritical CO2. For additional information, please see the discussion of

MITs in the final rule preamble.

To meet the requirements at §146.88(e), Class VI wells will be equipped with some type of

continuous computer-based monitoring device that will be connected to alarms and the shut-off

system. EPA does not believe it is necessary to specify what type of equipment is to be used to

trigger the shut-off system. Instead, the regulation allows the owner or operator some flexibility in

deciding what equipment and alarms should be installed to allow site specific flexibility and to make

use of improvements in technology. The technology for continuous monitoring is available and is

currently in fairly wide use. The combination of computer-driven continuous pressure monitoring

linked to an automatic injection shut-off provides maximum protection of USDWs from

endangerment and provides the earliest warning to owners or operators that well repairs need to be

performed.

Commenter Name: Daniel Plath Letter ID: 0188

Commenter Organization: NiSource, Inc. Comment ID: 25239

Comment: 6. Automatic Downhole Shut-off Systems (146.88) 

The Rule proposes to require automatic downhole shut-off subsurface safety 

valves. Experience by multiple natural gas storage operators, including Columbia 

is that subsurface safety valves actually increase the safety risks to the 

public and company personnel. Some operators, including ours, have even realized 

that the theoretical benefit does not out weigh the real world risks and have 

removed them from most of their wells. The safety valves have been relegated to 

the role of a niche application where additional safety features are necessary, 

e.g. a very high flow rate well in the midst of suburban housing because the 

product being stored has a high flammability characteristic. 

The Final Rule should not require the application of every safety feature in 

every instance as much as it should provide regulatory flexibility in 

recognition that the risks posed by all wells are not equal and that the best 

way is to tailor the design for the specific situation. 

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. However, the

Agency believes 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24347

Comment: 4. Down-Hole Shut-Off Valves 

EPA proposes to require automatic shut-off valves down hole as well as at the 

surface. Such a requirement is unnecessary and would be costly and completely 

unprecedented in the UIC program. In fact, the "down-hole" valves EPA is 

referring to are designed for off-shore use, and are intended to provide a shut 

off point below the sea bed in the event of a casing breach between the sea bed 

and the surface. Such valves are not appropriate for use deep under ground, and 

their use as proposed would increase well construction and operation costs and 

significantly complicate well testing and workovers. 

In any event, there is simply no justification to require the use of down-hole 

shut-off valves in the CO2 injection context. Class I hazardous waste injection 

wells are not required to have down-hole automatic shut-off valves, and there is 

no basis at all to suggest that CO2 injection entails higher risks warranting 

such costly and problematic measures. 

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 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24471

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(e) 
Proposed CCS Group Recommendations: (e) The owner or operator must install and 

use continuous recording devices to monitor: the injection pressure; the rate, 

volume, and temperature of the carbon dioxide stream and. THE OWNER OR 

OPERATOR MUST REGULARLY MONITOR the pressure on the annulus between the tubing 

and the long string casing and annulus fluid volume and. THE OWNER OR 

OPERATOR must install and use alarms and automatic down-hole shut-off 

systems, designed to alert the operator and shut-in the well when operating 

parameters such as injection rate, injection pressure, or other parameters 

approved by the Director diverge beyond ranges and/or gradients specified in the 

permit; 

Basis for CCS Group Comments: Over-pressure protection is best achieved by 

ensuring compatibility of the casing/tubing material design strength with the 

surface injection (compression) system. Down-hole shut-in devices are not 

appropriate for this application. These devices are installed in the tubing 

string and are typically near the surface of the well. They're intended to seal 

the tubing in the event of catastrophic failure of the wellhead. These devices 

would provide little if any protection to USDWs. Is not practicable to install 

these devices deep within the well (e.g. shortly above the packer). Additionally 

these devices create a restriction on running other tools like logging tools in 

the well and therefore could limit an operators ability to do required 

monitoring and diagnostic work. Lastly, these devices require periodic testing 

and maintenance which could require either pulling the device by wireline or by 

pulling the entire tubing string depending on the type of device installed. 

Either of these activities would be disruptive and costly to the overall project 

operations. 

Response: EPA acknowledges that proper design of the well, including appropriate materials and

emplacement of casing and tubing, is essential to proper operation of the well. Such design,

however, does not eliminate the possibility of failure, e.g., due to over-pressurization as suggested

by the commenter. EPA believes that a multiple-barrier approach, which includes appropriate well

design as required at §146.86, suitable injection pressure limits as required at §146.88(a), and

automatic shut-off systems, as required at §146.88(e), is necessary to ensure protection of USDWs

from endangerment from the risks associated with CO2 GS.

Landing nipples, which are machined portions of the tubing that allow the seating of components–

such as safety valves—at a later time, can be used to deploy safety valves after the initial well

completion. EPA believes, however, that if the shut-off system is not deployed until the failure

occurs, CO2 will be free to flow out of the well until the shut-off valve is deployed. Since installing

the new shut-off system will require getting the device to the site, setting up a rig, and deploying the

device down the well, a significant amount of time could elapse following an adverse event before

the well is sealed. EPA believes that the risks of uncontrolled CO2 flow are too great to be allowed

for such a length of time. 

As described above, 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 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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24472

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(f) 

Proposed CCS Group Recommendations: (f) If an down-hole automatic shutdown 

is triggered or a loss of mechanical integrity is discovered, the owner or 

operator must immediately investigate and identify as expeditiously as possible 

the cause of the shutoff. If, upon such investigation, the well appears to 

be lacking mechanical integrity, or if monitoring required under paragraph (e) 

of this section otherwise indicates that the well may be lacking mechanical 

integrity, the owner or operator must: 

Basis for CCS Group Comments: Revisions made here to make this subsection 

conform with changes to 146.88(e) above. 

Response: As described above, 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

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. Please see the final rule and preamble for

additional information on EPA's final approach.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24529

Comment: Rule Provisions or Federal Register Cite: 146.88(e) 

EPA Preamble Question: 22. EPA seeks comment on the merits of requiring downhole shut-off valves in GS wells. EPA Notice 43511. 

CSC Response: Over-pressure protection is best achieved by ensuring 

compatibility of the casing/tubing material design strength with the surface 

injection (compression) system. Down-hole shut-in devices are not appropriate 

for this application. These devices are installed in the tubing string and are 

typically near the surface of the well. They are used in off-shore applications 

where they are intended to seal the tubing at or near the ocean floor in the 

event that the tubing is severed above that point. These devices were not 

designed for use deep underground and would provide little if any protection to 

USDWs. It is not practicable to install these devices deep underground (e.g. 

shortly above the packer). Additionally these devices would create a restriction 

on running other tools like logging tools in the well and therefore could limit 

an operator’s ability to do required monitoring and diagnostic work. Lastly, 

these devices require periodic testing and maintenance which could require 

either pulling the device by wireline or by pulling the entire tubing string 
depending on the type of device installed. Either of these activities would be 

disruptive and costly to the overall project operations. 

Response: As described above, 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

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.

Commenter Name: Jeff W. Sheets Letter ID: 0192

Commenter Organization: ConocoPhillips Comment ID: 23896

Comment: - Automatic shut-in is appropriate, but we recommend not pursuing the proposed 

requirement for downhole shut off devices. Down hole shut off valves are 

designed for offshore or other site-specific risks and should be added on a 

site-specific basis when warranted. In many cases, surface shut-in is adequate 

and sufficiently protective. 

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 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. 

The GS rule, at §146.88(e)(3), requires the installation of down-hole shut-off devices for Class VI

wells located in the offshore submerged lands within the jurisdiction of a State UIC program. The

Agency believes that the unique construction and operational conditions for offshore Class VI wells,

including isolation from shorelines and the need to construct wells through the water column and the

subsurface, may delay response time in the event of well difficulties. These conditions merit

requiring automatic down-hole shut-off devices for offshore wells in the submerged lands of a State. 

While EPA acknowledges that the likelihood of damage to onshore facilities is lower than that for

off-shore facilities, down-hole shut-off valves are still commonly used in onshore facilities such as

acid gas injection wells and high pressure, high-temperature wells. While valve failure is a concern,

EPA believes that technology has advanced sufficiently to make valve failure a rare occurrence and

to appropriately handle such failure if it occurs. For example, wireline retrievable devices can allow

repair or replacement of damaged devices without necessitating pulling the tubing.

EPA believes that requiring the installation of automatic surface shut-off devices for onshore wells

(and affording Director's discretion to require down-hole devices where necessary) and automatic

down-hole shut-off devices for offshore wells in submerged lands within the jurisdiction of a State

ensures that proper precautions are taken to prevent subsurface fluid movement and ensure protection

of USDWs.
Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24592

Comment: Rule Provisions: 146.88(e) 

EPA Rule Issue: 22. EPA seeks comment on the merits of requiring down-hole shutoff valves in GS wells. EPA Notice 43511. 

Anadarko Petroleum Corporation (APC) Response: Over-pressure protection is best 

achieved by ensuring compatibility of the casing/tubing material design strength 

with the surface injection (compression) system. Down-hole shut-in devices are 

not appropriate for this application. These devises are installed in the tubing 

string and are typically near the surface of the well. They’re intended to seal 

the tubing in the event of catastrophic failure of the wellhead. These devises 

would provide little if any protection to USDWs. It is not practicable to 

install these devises deep within the well (e.g. shortly above the packer). 

Additionally these devises create a restriction on running other tools like 

logging tools in the well and therefore could limit an operator’s ability to 

perform required monitoring and diagnostic work. Lastly, these devises require 

periodic testing and maintenance which could require either pulling the devise 

by wireline or by pulling the entire tubing string depending on the type of 

devise installed. Either of these activities would be disruptive and costly to 

the overall project operations. 

To address EPA’s concerns while maintaining the necessary operational 

flexibility, APC recommends EPA allow for the installation of landing nipples at 

appropriate points in the tubing string which would allow use of wireline 

retrievable plugs when needed. 

Response: EPA acknowledges that proper design of the well, including appropriate materials and

emplacement of casing and tubing, is essential to proper operation of the well. Such design,

however, does not eliminate the possibility of failure, e.g., due to over-pressurization as suggested

by the commenter. EPA believes that a multiple-barrier approach, which includes appropriate well

design as required at §146.86, suitable injection pressure limits as required at §146.88(a), and

automatic shut-off systems, as required at §146.88(e), is necessary to ensure protection of USDWs

from endangerment from the risks associated with CO2 GS.

Landing nipples, which are machined portions of the tubing that allow the seating of components–

such as safety valves—at a later time, can be used to deploy safety valves after the initial well

completion. EPA believes, however, that if the shut-off system is not deployed until the failure

occurs, CO2 will be free to flow out of the well until the shut-off valve is deployed. Since installing

the new shut-off system will require getting the device to the site, setting up a rig, and deploying the

device down the well, a significant amount of time could elapse following an adverse event before

the well is sealed. EPA believes that the risks of uncontrolled CO2 flow are too great to be allowed

for such a length of time. 

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. However, the Agency

believes 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.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24695

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(e) 

Anadarko Petroleum Corporation (APC) Comments: (e) The owner or operator must 

install and use continuous recording devices to monitor: the injection pressure; 

the rate, volume, and temperature of the carbon dioxide stream and. THE 

OWNER OR OPERATOR MUST REGULARLY MONITOR the pressure on the annulus between

the 

tubing and the long string casing and annulus fluid volume and. THE OWNER OR 

OPERATOR must install and use alarms and automatic down-hole shut-off 

systems, designed to alert the operator and shutin the well when operating 

parameters such as injection rate, injection pressure, or other parameters 

approved by the Director diverge beyond ranges and/or gradients specified in the 

permit; 

Rationale: Over-pressure protection is best achieved by ensuring compatibility 

of the casing/tubing material design strength with the surface injection 

(compression) system. Down-hole shut-in devices are not appropriate for this 

application. These devises are installed in the tubing string and are typically 

near the surface of the well. They’re intended to seal the tubing in the event 

of catastrophic failure of the wellhead. These devises would provide little if 

any protection to USDWs. Is not practicable to install these devises deep within 

the well (e.g. shortly above the packer). Additionally these devises create a 

restriction on running other tools like logging tools in the well and therefore 

could limit an operators ability to do required monitoring and diagnostic work. 

Lastly, these devises require periodic testing and maintenance which could 

require either pulling the devise by wireline or by pulling the entire tubing 

string depending on the type of devise installed. Either of these activities 

would be disruptive and costly to the overall project operations. 

A more appropriate approach would be installation of landing nipples at 

appropriate points in the tubing string which would allow use of wireline 

retrievable plugs when needed. 

Response: As described above, 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

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. Please see the final rule and preamble for

additional information on EPA's final approach.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24696

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88(f) 

Anadarko Petroleum Corporation (APC) Comments: (f) If aN down-hole automatic 

shutdown is triggered or a loss of mechanical integrity is discovered, the owner 

or operator must immediately investigate and identify as expeditiously as 

possible the cause of the shutoff. If, upon such investigation, the well 

appears to be lacking mechanical integrity, or if monitoring required under 

paragraph (e) of this section otherwise indicates that the well may be lacking 

mechanical integrity, the owner or operator must: 

Rationale: Technical clarification given changes above. 

Response: As described above, 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

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. Please see the final rule and preamble for

additional information on EPA's final approach.

Commenter Name: Chris M. Hobson Letter ID: 0201

Commenter Organization: Southern Company Comment ID: 22171

Other EPA Comment Codes and Descriptions: 4710 2.7.1 Proposed submissions required for

permit applications (seeking comment) 

Comment: While some requirements are appropriate for all Class VI wells, as a general 

matter operating and monitoring requirements for individual Class VI projects 

should be set forth in a Director-approved plan as part of the permit 

application and approval process. For example, while Southern Company supports a 

default requirement for automatic shut-off mechanisms for Class VI wells, we 

oppose a uniform requirement for down-hole shut-off valves. ¡d. at 34511. These 

valves are designed to meet unique offshore risks and are, in many instances, 

ill-suited to UIC operations, including C02 GS. A requirement for down-hole 

shut-off valves would provide little benefit but would come at a significant 

cost and would preclude the use of some tools that are critical to operation, 

monitoring, and repair of CO2 GS wells. 

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 GS rule, at §146.88(e)(3), requires the installation of down-hole shut-off devices for Class VI

wells located in the offshore submerged lands within the jurisdiction of a State UIC program. The

Agency agrees 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. These conditions merit

requiring automatic down-hole shut-off devices for offshore wells in the submerged lands of a State. 

While EPA acknowledges that the likelihood of damage to onshore facilities is lower than that for

off-shore facilities, down-hole shut-off valves are still commonly used in onshore facilities such as

acid gas injection wells and high pressure, high-temperature wells. While valve failure is a concern,

EPA believes that technology has advanced sufficiently to make valve failure a rare occurrence and

to appropriately handle such failure if it occurs. For example, wireline retrievable devices can allow

repair or replacement of damaged devices without necessitating pulling the tubing.

EPA believes that requiring the installation of automatic surface shut-off devices for onshore wells

(and affording Director's discretion to require down-hole devices where necessary) and automatic

down-hole shut-off devices for offshore wells in submerged lands within the jurisdiction of a State

ensures that proper precautions are taken to prevent subsurface fluid movement and ensure protection

of USDWs.

Commenter Name: John King Letter ID: 0211

Commenter Organization: Shell Exploration and Production Company

(SEPCo)

Comment ID:

22773

Comment: 2. Down-Hole Shut-Off Valves 

EPA proposes to require automatic shut-off valves down hole as well as at the 

surface. Such a requirement would be costly and is completely unprecedented in 

the UIC program. Down hole shut off valves would increase well construction and 

operation costs, and could significantly complicate well testing and workovers. 

Class I hazardous waste injection wells are not required to have down- hole 

automatic shut-off valves, and there is no basis to suggest that CO2 injection 

entails higher risks warranting costly additional safety measures that would 

interfere with monitoring and potentially with any necessary well remediation. 

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. However, the

Agency believes 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 clarifies that down-hole shut-off devices are currently used in situations where loss of well

integrity could result in damage to the well or harm to humans (e.g., near high-density population

areas, or in onshore acid gas injection; IEA, 2003). EPA has identified examples of documented

logging techniques, including ultrasonic and temperature logs, that can be performed with an

automatic down-hole device emplaced (Julian, et al. 2007; Somaschini, et al. 2009). They are also

used in high pressure, high temperature onshore wells and in permafrost areas.

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.

Commenter Name: Diane VanDe Hei Letter ID: 0213

Commenter Organization: Association of Metropolitan Water Agencies

(AMWA)

Comment ID:

22946

Comment: - 73 FR 435110 -EPA seeks comment on the merits of requiring down-hole shut-off 

valves in geosequestration wells. 

Response: AMWA supports requiring down-hole shut-off valves in all 

geosequestration wells as these valves could provide a line of defense against 

contamination of USDW in the event of a defective injection process. 

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. However, the

Agency believes 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.

Commenter Name: Ronald Evans Letter ID: 0215

Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24304

Comment: 2. EPA Proposed §146.88(e) The owner or operator must install and use 

continuous recording devices to monitor: The injection pressure; the 

rate, volume, and temperature of the carbon dioxide stream; and the 

pressure on the annulus between the tubing and the long string casing 
and annulus fluid volume; and must install and use alarms and automatic 

down-hole shut-off systems, designed to alert the operator and shut-in 

the well when operating parameters such as annulus pressure, injection 

rate or other parameters approved by the Director diverge beyond 

permitted ranges and/or gradients specified in the permit; 

The installation and use of automatic down-hole shut-off systems creates a 

potential avenue for leakage and is unnecessary on land-based onshore systems. 

Down-hole shutoff systems, more commonly used in off-shore operations, serve to 

shut in the well and prevent reservoir fluids from exiting the wellbore. They 

are used in off-shore operations because of the risk of damage to the wellhead 

from atmospheric or anthropogenic phenomenon, such as a hurricane causing 

extensive platform damage or a ship colliding with a platform. But in an onshore 

injection system, a down-hole shut-off system will not determine or deter 

leakage of fluids in the wellbore and therefore is not effective in protecting 

USDWs. Also, the likelihood of damage to an onshore wellhead is extremely 

remote. The greater risk in a Class VI onshore operation is that the mechanics 

of the down-hole shut-off system will be compromised or malfunction. Such a 

malfunction would require removal of the tubing and shut-off system equipment, 

thereby creating a potential unwanted migration path. The use of automatic downhole shut-off systems should be limited to off-shore operations. 

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. EPA believes

that requiring the installation of automatic surface shut-off devices for onshore wells (and affording

Director's discretion to require down-hole devices where necessary) ensures that proper precautions

are taken to prevent subsurface fluid movement and ensure protection of USDWs.

The GS rule, at §146.88(e)(3), requires the installation of down-hole shut-off devices for Class VI

wells located in the offshore submerged lands within the jurisdiction of a State UIC program. The

Agency believes that the unique construction and operational conditions for offshore Class VI wells,

including isolation from shorelines and the need to construct wells through the water column and the

subsurface, may delay response time in the event of well difficulties. These conditions merit

requiring automatic down-hole shut-off devices for offshore wells in the submerged lands of a State. 

While EPA acknowledges that the likelihood of damage to onshore facilities is lower than that for

off-shore facilities, down-hole shut-off valves are still commonly used in onshore facilities such as

acid gas injection wells and high pressure, high-temperature wells. While valve failure is a concern,

EPA believes that technology has advanced sufficiently to make valve failure a rare occurrence and

to appropriately handle such failure if it occurs. For example, wireline retrievable devices can allow

repair or replacement of damaged devices without necessitating pulling the tubing.

Commenter Name: Ronald Evans Letter ID: 0215

Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24306

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule
language 

Comment: OPERATION INVOLVES OFF-SHORE INJECTION, THE OWNER OR OPERATOR

MUST 

INSTALL AND USE ALARMS AND AUTOMATIC DOWN-HOLE SHUT-OFF SYSTEMS, 

DESIGNED TO ALERT THE OPERATOR AND SHUT-IN THE WELL IF THE WELLHEAD IS 

DAMAGED OR WHEN OPERATING PARAMETERS SUCH AS ANNULUS PRESSURE,

INJECTION 

RATE OR OTHER PARAMETERS APPROVED BY THE DIRECTOR DIVERGE BEYOND 

PERMITTED RANGES AND/OR GRADIENTS SPECIFIED IN THE PERMIT; 

(f) If aN down-hole automatic shutdown is triggered or a loss of 

mechanical integrity is discovered, the owner of operator must 

immediately investigate and identify as expeditiously as possible the 

cause of the shutoff. 

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 GS rule, at §146.88(e)(3), requires the installation of down-hole shut-off devices for Class VI

wells located in the offshore submerged lands within the jurisdiction of a State UIC program. The

Agency believes that the unique construction and operational conditions for offshore Class VI wells,

including isolation from shorelines and the need to construct wells through the water column and the

subsurface, may delay response time in the event of well difficulties. These conditions merit

requiring automatic down-hole shut-off devices for offshore wells in the submerged lands of a State. 

EPA believes that requiring the installation of automatic surface shut-off devices for onshore wells

(and affording Director's discretion to require down-hole devices where necessary) and automatic

down-hole shut-off devices for offshore wells in submerged lands within the jurisdiction of a State

ensures that proper precautions are taken to prevent subsurface fluid movement and ensure protection

of USDWs, human health, and the environment.

Commenter Name: Darrick Eugene Letter ID: 0223

Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23986

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: EPA Proposed §146.88(e) The owner or operator must install and use 

continuous recording devices to monitor: The injection pressure; the 

rate, volume, and temperature of the carbon dioxide stream; and the 

pressure on the annulus between the tubing and the long string casing 

and annulus fluid volume; and must install and use alarms and automatic 

down-hole shut-off systems, designed to alert the operator and shut-in 

the well when operating parameters such as annulus pressure, injection 

rate or other parameters approved by the Director diverge beyond 

permitted ranges and/or gradients specified in the permit; 
The installation and use of automatic down-hole shut-off systems creates a 

potential avenue for leakage and is unnecessary on land-based onshore systems. 

Down-hole shut-off systems, more commonly used in off-shore operations, serve to 

shut in the well and prevent reservoir fluids from exiting the wellbore. They 

are used in off-shore operations because of the risk of damage to the wellhead 

from atmospheric or anthropogenic phenomenon, such as a hurricane causing 

extensive platform damage or a ship colliding with a platform. But in an onshore 

injection system, a down-hole shut-off system will not determine or deter 

leakage of fluids in the wellbore and therefore is not effective in protecting 

USDWs. Also, the likelihood of damage to an onshore wellhead is extremely 

remote. The greater risk in a Class VI onshore operation is that the mechanics 

of the down-hole shut-off system will be compromised or malfunction. Such a 

malfunction would require removal of the tubing and shut-off system equipment, 

thereby creating a potential unwanted migration path. The use of automatic downhole shut-off systems should be limited to off-shore operations. 

Furthermore, the requirement to continuously monitor the annulus fluid volume is 

impractical, because it does not provide any meaningful data regarding potential 

problems with the operation of the well. Requiring the continuous monitoring of 

the amount of annulus fluid added during operations is more practical and will 

reveal potential leakage paths. TxCCSA recommends the following: 

§146.88(e) The owner or operator must install and use continuous 

recording devices to monitor: The injection pressure; the rate, volume, 

and temperature of the carbon dioxide stream; and the pressure on the 

annulus between the tubing and the long string casing and THE VOLUME 

OF annulus fluid added to the annulus VOLUME; and the owner or 

operator must install and use alarms and automatic DOWN-HOLE shut-off 

systems, designed to alert the operator and shut-in off the well when 

operating parameters such as annulus pressure, injection rate or other 

parameters approved by the Director diverge beyond permitted ranges 

and/or gradients specified in the permit. IF THE OPERATION INVOLVES 

OFF-SHORE INJECTION, THE OWNER OR OPERATOR MUST INSTALL AND USE

ALARMS 

AND AUTOMATIC DOWN-HOLE SHUT-OFF SYSTEMS, DESIGNED TO ALERT THE

OPERATOR 

AND SHUT-IN THE WELL IF THE WELLHEAD IS DAMAGED OR WHEN OPERATING 

PARAMETERS SUCH AS ANNULUS PRESSURE, INJECTION RATE OR OTHER

PARAMETERS 

APPROVED BY THE DIRECTOR DIVERGE BEYOND PERMITTED RANGES AND/OR 

GRADIENTS SPECIFIED IN THE PERMIT; 

(f) If aN down-hole automatic shutdown is triggered or a loss of 

mechanical integrity is discovered, the owner of operator must 

immediately investigate and identify as expeditiously as possible the 

cause of the shutoff. 

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 GS rule, at §146.88(e)(3), requires the installation of down-hole shut-off devices for Class VI

wells located in the offshore submerged lands within the jurisdiction of a State UIC program. The

Agency believes that the unique construction and operational conditions for offshore Class VI wells,

including isolation from shorelines and the need to construct wells through the water column and the

subsurface, may delay response time in the event of well difficulties. These conditions merit

requiring automatic down-hole shut-off devices for offshore wells in the submerged lands of a State. 

EPA believes that requiring the installation of automatic surface shut-off devices for onshore wells

(and affording Director's discretion to require down-hole devices where necessary) and automatic

down-hole shut-off devices for offshore wells in submerged lands within the jurisdiction of a State

ensures that proper precautions are taken to prevent subsurface fluid movement and ensure protection

of USDWs.

Regarding annulus fluid volume, EPA believes that knowing annulus fluid volume, as required at

§146.88(e), is a necessary component of monitoring well mechanical integrity, but believes that

monitoring the annulus fluid volume added is sufficient to meet the intent of continuous monitoring

of the pressure on the annulus. The final GS rule at §146.90 (b) requires that owners or operators use

continuous recording devices to monitor injection pressure, rate and volume; the pressure on the

annulus between the tubing and the long string casing; and the annulus fluid volume added.

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21691

Comment: (vi) Injection Well Operation & Mechanical Integrity Requirements 

Consistent with the earlier discussion about blanket construction limitations, 

HEI also disagrees with universal mandates regarding certain CO2 injection 

operations. EPA should not include automatic downhole shut-in devices as a 

standard requirement for CO2 injection wells (section 146.88(e)). An across-theboard requirement for installation of downhole devices is excessive - 

unsupported by technical knowledge and industry experience - and would impose 

unnecessary costs. Overpressure protection is best achieved by ensuring 

compatibility of the casing/tubing material design strength with the surface 

injection (compression) system. Downhole shut-in devices may be appropriate, 

however, for site-specific situations (such as offshore), but they should not be 

mandated for all storage sites. Rather, the requirement of downhole shut-in 

devices should be left to the discretion of the Director. 

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. EPA believes

that requiring the installation of automatic surface shut-off devices for onshore wells (and affording

Director's discretion to require down-hole devices where necessary) ensures that proper precautions
are taken to prevent subsurface fluid movement and ensure protection of USDWs, human health, and

the environment.

The GS rule, at §146.88(e)(3), requires the installation of down-hole shut-off devices for Class VI

wells located in the offshore submerged lands within the jurisdiction of a State UIC program. The

Agency believes that the unique construction and operational conditions for offshore Class VI wells,

including isolation from shorelines and the need to construct wells through the water column and the

subsurface, may delay response time in the event of well difficulties. These conditions merit

requiring automatic down-hole shut-off devices for offshore wells in the submerged lands of a State. 

While EPA acknowledges that the likelihood of damage to onshore facilities is lower than that for

off-shore facilities, down-hole shut-off valves are still commonly used in onshore facilities such as

acid gas injection wells and high pressure, high-temperature wells. While valve failure is a concern,

EPA believes that technology has advanced sufficiently to make valve failure a rare occurrence and

to appropriately handle such failure if it occurs so that USDWs will not be endangered. For example,

wireline retrievable devices can allow repair or replacement of damaged devices without

necessitating pulling the tubing.

EPA believes that requiring the installation of automatic surface shut-off devices for onshore wells

(and affording Director's discretion to require down-hole devices where necessary) and automatic

down-hole shut-off devices for offshore wells in submerged lands within the jurisdiction of a State

ensures that proper precautions are taken to prevent subsurface fluid movement and ensure protection

of USDWs.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21742

Comment: (vi) Injection Well Operation & Mechanical Integrity Requirements 

Consistent with the earlier discussion about blanket construction limitations, 

BP also disagrees with universal mandates regarding certain CO2 injection 

operations. EPA should not include automatic downhole shut-in devices as a 

standard requirement for CO2 injection wells (section 146.88(e)). An across-theboard requirement for installation of downhole devices is excessive - 

unsupported by technical knowledge and industry experience - and would impose 

unnecessary costs. Overpressure protection is best achieved by ensuring 

compatibility of the casing/tubing material design strength with the surface 

injection (compression) system. Downhole shut-in devices may be appropriate, 

however, for site-specific situations (such as offshore), but they should not be 

mandated for all storage sites. Rather, the requirement of downhole shut-in 

devices should be left to the discretion of the Director. 

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. EPA believes

that requiring the installation of automatic surface shut-off devices for onshore wells (and affording

Director's discretion to require down-hole devices where necessary) ensures that proper precautions
are taken to prevent subsurface fluid movement and ensure protection of USDWs.

The GS rule, at §146.88(e)(3), requires the installation of down-hole shut-off devices for Class VI

wells located in the offshore submerged lands within the jurisdiction of a State UIC program. The

Agency believes that the unique construction and operational conditions for offshore Class VI wells,

including isolation from shorelines and the need to construct wells through the water column and the

subsurface, may delay response time in the event of well difficulties. These conditions merit

requiring automatic down-hole shut-off devices for offshore wells in the submerged lands of a State. 

While EPA acknowledges that the likelihood of damage to onshore facilities is lower than that for

off-shore facilities, down-hole shut-off valves are still commonly used in onshore facilities such as

acid gas injection wells and high pressure, high-temperature wells. While valve failure is a concern,

EPA believes that technology has advanced sufficiently to make valve failure a rare occurrence and

to appropriately handle such failure if it occurs. For example, wireline retrievable devices can allow

repair or replacement of damaged devices without necessitating pulling the tubing.

EPA believes that requiring the installation of automatic surface shut-off devices for onshore wells

(and affording Director's discretion to require down-hole devices where necessary) and automatic

down-hole shut-off devices for offshore wells in submerged lands within the jurisdiction of a State

ensures that proper precautions are taken to prevent subsurface fluid movement and ensure protection

of USDWs.

Commenter Name: Neeraj Gupta Letter ID: 0229

Commenter Organization: Battelle Energy Technology (BET) Comment ID: 21847

Comment: Page 86, Downhole Shut-off valves - We would be interested in more detail on the 

downhole shut-off valves, their use in on-shore conditions in other injection 

wells, and suggested criteria for shut-down. It appears that so far such valves 

have mainly been applied in offshore wells. We are not aware of these in any of 

the injection wells or EOR operations we have encountered. None of the MRCSP 

Phase II test permits have required this or mentioned it. This would seem to be 

somewhat redundant with annular pressure system. 

Response: Down-hole shut-off systems are typically installed below the packer on a well and are

used to stem uncontrolled flow of fluids out of the well. The devices default to the closed position

and are opened by application of force from the surface. Pressure can be applied by the fluid itself or

through a hydraulic signal from the surface. They are typically set to close when the pressure in the

tubing drops below a pre-determined level. It is possible to set them to deploy based on other

triggers. The devices can either be deployed on the tubing or by wire line. Tubing-deployed devices

have the advantage of not constricting the flow in the tubing, but replacing them requires removal of

the tubing. Wire line devices constrict the flow in the tubing, causing reduced pressure in the well,

but these are easier to deploy and retrieve. Down-hole shut off valves are required in offshore oil

and gas wells; however, they are considered standard on other wells where well damage is likely or

where well failure could result in the release of toxic chemicals. Several types of Class II wells

commonly use down-hole shut-off systems and include high pressure/high temperature wells, acid

gas injection, and wells located in permafrost regions. 

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. However, the Agency

believes 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.

Commenter Name: Robert E. Carter Jr. Letter ID: 0236

Commenter Organization: Indiana Department of Natural Resources (IDNR) Comment ID: 29218

Comment: States like Indiana with a proven track record of effectively managing similar 

programs have indeed demonstrated an ability to adapt to evolving technologies 

and we believe do possess the capability to effectively address long-term 

storage issues. In fact, as indicated earlier in our comments, many of the longterm issues associated with CCGS operations will be outside the purview of the 

UIC Program and will need to be addressed by states as they enact appropriate 

CCGS legislation. EPA should consider implementing rules which afford states 

with the greatest flexibility to select regulatory options that are best suited 

to their specific needs and conditions. Specific examples of requirements that 

may be too prescriptive include: 

3. Any requirement that down-hole shut off valves be installed in GS wells. 

Response: Regarding down-hole shutoff devices, after evaluating the risks and benefits of downhole shut-off systems and considering additional research, EPA will not require automatic downhole shut-off devices for onshore Class VI wells since they are 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. However, the Agency believes 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.

Commenter Name: Philip Papadeas Letter ID: 0238

Commenter Organization: Sandia Technologies, LLC Comment ID: 23355

Comment: Downhole shut off systems or valves are considered necessary for Class I wells 

which operate with large volumes and in some cases greater pressures. The 

Agency should not specify the type of tubular and well operations system. 

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. However, the

Agency believes 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.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23244

Comment: 22. EPA seeks comment on the merits of requiring down-hole shut-off valves in GS 

wells. EPA Notice 43511. 

Requiring down-hole shut-off valves may be problematic. To protect the entire 

tubing-casing annulus they would need to be installed at or below the injection 

packer. This may make the tool prone to failure. These valves may restrict or 

preclude the running of down hole monitoring or logging tools. Inclusion of a 

seating nipple directly above the injection packer which would allow the 

installation of a wire line set plug may be more appropriate. 

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. However, the

Agency believes 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.

Landing nipples, which are machined portions of the tubing that allow the seating of components–

such as safety valves—at a later time, can be used to deploy safety valves after the initial well

completion. EPA believes, however, that if the shut-off system is not deployed until the failure

occurs, CO2 will be free to flow out of the well until the shut-off valve is deployed. Since installing

the new shut-off system will require getting the device to the site, setting up a rig, and deploying the

device down the well, a significant amount of time could elapse following an adverse event before

the well is sealed. EPA believes that the risks of uncontrolled CO2 flow are too great to be allowed

for such a length of time.

Commenter Name: Michel Paque Letter ID: 0259
Commenter Organization: Ground Water Protection Council Comment ID: 24912

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88 

EPA Proposal: (e) The owner or operator must install and use continuous 

recording devices to monitor: The injection pressure; the rate, volume, and 

temperature of the carbon dioxide stream; and the pressure on the annulus 

between the tubing and the long string casing and annulus fluid volume; and must 

install and use alarms and automatic down-hole shut-off systems, designed to 

alert the operator and shut-in the well when operating parameters such as 

annulus pressure, injection rate or other parameters approved by the Director 

diverge beyond permitted ranges and/or gradients specified in the permit; 

GWPC Recommendations: (e) The owner or operator must install and use continuous 

recording devices to monitor: the injection pressure; the rate, volume, and 

temperature of the carbon dioxide stream. The owner or operator must regularly 

monitor the pressure on the annulus between the tubing and the long string 

casing. The owner or operator must install, test and use alarms and automatic 

shut-off systems, designed to alert the operator and shut-in the well when 

operating parameters such as injection rate, injection pressure, or other 

parameters approved by the Director diverge beyond ranges and/or gradients 

specified in the permit; 

Rationale: Over-pressure protection is best achieved by ensuring compatibility 

of the casing/tubing material design strength with the surface injection 

(compression) system. Down-hole shut-in devices may be appropriate, however, 

for site-specific situations of unique potential impact (such as offshore or 

near airports), but they should not be mandated for all injection sites. 

Response: EPA acknowledges that proper design of the well, including appropriate materials and

emplacement of casing and tubing, is essential to proper operation of the well so that USDWs are

protected. Such design, however, does not eliminate the possibility of failure, e.g., due to overpressurization as suggested by the commenter. EPA believes that a multiple-barrier approach, which

includes appropriate well design as required at §146.86, suitable injection pressure limits as required

at §146.88(a), and automatic shut-off systems, as required at §146.88(e), is necessary to ensure

protection of USDWs from endangerment from the risks associated with CO2 GS.

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. However, the Agency

believes 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.

While EPA acknowledges that the likelihood of damage to onshore facilities is lower than that for

off-shore facilities, down-hole shut-off valves are still commonly used in onshore facilities such as

acid gas injection wells and high pressure, high-temperature wells. While valve failure is a concern,

EPA believes that technology has advanced sufficiently to make valve failure a rare occurrence and

to appropriately handle such failure if it occurs. For example, wireline retrievable devices can allow

repair or replacement of damaged devices without necessitating pulling the tubing.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24913

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.88 

EPA Proposal: (f) If a down-hole automatic shutdown is triggered or a loss of 

mechanical integrity is discovered, the owner or operator must immediately 

investigate and identify as expeditiously as possible the cause of the shutoff. 

If, upon such investigation, the well appears to be lacking mechanical 

integrity, or if monitoring required under paragraph (e) of this section 

otherwise indicates that the well may be lacking mechanical integrity, the owner 

or operator must: 

GWPC Recommendations: (f) If an automatic shutdown is triggered or a loss of 

mechanical integrity is discovered, the owner or operator must immediately 

investigate and identify as expeditiously as possible the cause. If, upon such 

investigation, the well appears to be lacking mechanical integrity, or if 

monitoring required under paragraph (e) of this section otherwise indicates that 

the well may be lacking mechanical integrity, the owner or operator must: 

Rationale: Eliminates requirement for down-hole shutoff device. Although the 

use of downhole shutoff valves may be needed in some applications, their 

required use would be less than ideal for many reasons such as the fact that 

since they are a downhole installation, integrity and maintenance of the valves 

is difficult. Further the installation of surface valves would allow for more 

control and provide for visual inspection. Since the key is to shut down the 

injection flow if a parameter is exceeded, the use of surface valves would be 

just as effective as downhole valves. 

Response: As described above, 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

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. Please see the final rule and preamble for

additional information on EPA's final approach.
Letter ID: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22808

Comment: III A. 4 Proposed Injection Well Operating Requirements 

W. EPA seeks comment on the merits of requiring down-hole shut-off valves in GS 

wells. 

IOGCC Response: There should be no hard and fast requirement for a down-hole 

shut-off valve in a GS well. Down-hole shut-off valves may, however, at Director 

discretion provide a necessary extra level of protection in more sensitive 

settings. 

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. However, the

Agency believes 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.

Commenter Name: Michael Moore Letter ID: 0265

Commenter Organization: North American Carbon Capture & Storage

Association (NACCSA)

Comment ID:

22866

Comment: Finally, the proposed regulations also would require the use of automatic downhole shut-off systems. We question the need for such a mandatory requirement 

because in some applications such systems could cause operational problems and 

add risk during maintenance operations. These risks seem to outweigh the 

benefits of the use of such systems in GS applications. Moreover, such systems 

are not required in other applications, such as natural gas which arguably pose 

greater hazards than the storage of carbon dioxide. Instead of making the use 

of automatic down-hole shut-off systems mandatory, the Administrator should be 

given discretion to require their installation and use when site-specific data 

and reservoir characteristics indicate that the benefits of requiring such 

systems outweigh the risks of their use. 

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. However, the

Agency believes 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 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 where necessary ensures that proper precautions

are taken to prevent subsurface fluid movement and ensure protection of USDWs.

Commenter Name: Mark Vickery Letter ID: 0280

Commenter Organization: Texas Commission on Environmental Quality Comment ID: 24102

Comment: TCEQ also advises against requirement of automatic down-hole shut off devices in 

well designs. This position is based on TCEQ's UIC program experience regarding 

the expense and time requirements for acquisition of workover rigs and 

contractor services to make down-hole repairs (well workovers). Also, in our 

program's experience, abrupt activation of shut-off devices may cause damage to 

the well tubulars and elements upstream of the well in the CO2 conveyance system 

(pipelines, valves, etc.). In response to significant variations in well annulus 

monitoring data, an expeditious but controlled ramping down of well injection 

rates is considered to pose less stress on overall mechanical integrity of the 

well than an abrupt shut off of flow through the well. Additionally, from TCEQ's 

experience, use of such devices in four Class I wells imposed a restriction in 

the inside diameter of the injection tubing and compromised ability to perform 

conventional mechanical integrity testing. 

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. However, the

Agency believes 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 where necessary ensures that proper precautions

are taken to prevent subsurface fluid movement and ensure protection of USDWs.

EPA acknowledges that abrupt shut-offs are not the optimal way to shut down an injection well.

These automatic shut-off systems, however, are intended only to activate when a severe drop in

pressure occurs. This is only likely to occur if there has been serious damage to the wellhead or other

surface features or if there has a sudden increase in pressure in the subsurface (i.e., a well blowout).

In such conditions, any potential further damage to the well would be minor in comparison to the

consequences of allowing CO2 to escape out of the well. EPA also notes that activation of the shutoff valve means that damage has likely already occurred to the well and any additional damage

caused by the shut-off valve is likely to be minimal in comparison to the damage that may be caused

by a malfunction.

Commenter Name: Brian Williams Letter ID: 0507

Commenter Organization: BP Alternative Energy Comment ID: 21168

Comment: And finally, the standard requirement for down hole shut-in devices. BP 

disagrees with the rules to include down hole shut-in devices as a standard 

requirement for injection wells. Overpressure protection is best achieved by 

ensuring compatibility of a casing, tubing, material strength design with the 

surface injection compression system. Down hole shut-in devices may be 

appropriate, however, for site-specific situations of unique potential impact, 

of impact, for example, Offshore or near airports, but they should not be 

mandated for all injection sites. 

Response: EPA acknowledges that proper design of the well, including appropriate materials and

emplacement of casing and tubing, is essential to proper operation of the well. Such design,

however, does not eliminate the possibility of failure, e.g., due to over-pressurization as suggested

by the commenter. EPA believes that a multiple-barrier approach, which includes appropriate well

design as required at §146.86, suitable injection pressure limits as required at §146.88(a), and

automatic shut-off systems, as required at §146.88(e), is necessary to ensure protection of USDWs

from endangerment from the risks associated with CO2 GS.

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. However, the Agency

believes 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.
Comment Code: 4250 2.4.3 Corrosion monitoring and control 

Individual Comments

Commenter Name: Kenneth Nemeth Letter ID: 0176

Commenter Organization: Southern States Energy Board Comment ID: 23546

Comment: demonstrated by the owner/operator. Corrosion monitoring is unnecessary, as it 

would be assumed that compatible well construction materials suitable for use 

with site-specific CO2 composition would be consistent. 

Response: EPA disagrees with commenter's assertions that corrosion monitoring is unnecessary or

excessive. CO2 in the presence of water (including water with NOx, SOx, and H2S impurities) can

be corrosive to well materials and cements. Thus, although a CO2 stream may be dry, the potential

for corrosion of well materials down-hole, where the injectate can potentially mix with water in the

target formation, must be considered. While the construction requirements at §146.86 were designed

to protect against corrosion, EPA believes that multiple barriers against corrosion-related failures,

including construction and monitoring requirements, are necessary in order to protect USDWs from

endangerment.

Several laboratory studies and a limited number of field studies have investigated and characterized

the effects of carbonic acid on well materials. Laboratory studies (e.g., Kutchko et al., 2007;

Kutchko et al., 2008; Akervoll, 2005) consistently identify alterations (typically carbonation) of

cement as the result of interactions between cement and CO2-saturated brine. 

Currently, there are only a few analyses of cement from wells that have been in prolonged contact

with CO2 in actual field (down-hole) conditions. Evaluation of cement from a well at the Scurry

Area Canyon Reef Operators Committee (SACROC) site showed alteration, but did not show

degradation that compromised the structural integrity of the cement (Carey et al., 2007). In another

study, cement samples were collected and analyzed from a CO2 production well in a natural CO2

reservoir in Colorado exposed to a CO2-water down-hole environment for 30 years (Crow et al.,

2008). The study found evidence of reaction between the CO2-rich water and the cement. 

Oil industry research also addresses the effects of corrosion of steel tubing and pipes. Lopez et al.

(2003) noted that 60 percent of oilfield failures are related to the effects of carbonic acid from

produced brines on carbon and low alloy steels. A report by CO2 Norway (2004) notes that in some

CO2 ER floods in the Permian Basin of Texas, bare carbon steel tubing has been used successfully. 

Laboratory investigation of cement alteration/degradation is an ongoing research area. Few fieldbased studies have been completed to date. Although the laboratory and field studies currently

available suggest that corrosion problems may not be serious, there is not enough data to rule out

potential corrosion problems of steel components of injection wells. Given the anticipated long

lifespan of a Class VI well and the difficulties that would be associated with a corrosion-related well

failure, EPA believes that corrosion monitoring in the down-hole environment is justified in order to

protect USDWs from endangerment.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24348

Comment: 5. Corrosion Monitoring 
As already discussed, CO2 is not corrosive in the absence of water and there is 

no basis to assume that GS wells will typically be used to inject corrosive 

fluids or will always be in contact with corrosive conditions in the injection 

zone. A general requirement for corrosion monitoring is therefore unnecessary 

and inappropriate. 

Even if there were some basis for corrosion concerns, a requirement for 

corrosion monitoring would be excessive, because the proposed rule already 

includes other provisions sufficient to address the risks corrosion would 

present. In particular, the proposed rule would require that injection wells be 

designed and constructed for their intended service. This requirement would 

address the potential for corrosion even if (as we recommend) the burdensome and 

unnecessary provisions expressly requiring use of corrosion-resistant materials 

is excised. In addition, the requirements for a tubing and packer design would 

protect against corrosion leaks, both by providing secondary containment of the 

injectate and by permitting continuous annulus pressure monitoring (also 

required) to ensure that corrosion leaks could be detected and repaired before 

both layers of containment would be breached. 

Response: EPA disagrees with commenter's assertions that corrosion monitoring is unnecessary or

excessive. CO2 in the presence of water (including water with NOx, SOx, and H2S impurities) can

be corrosive to well materials and cements. Thus, although a CO2 stream may be dry, the potential

for corrosion of well materials down-hole, where the injectate can potentially mix with water in the

target formation, must be considered. While the construction requirements at §146.86 were designed

to protect against corrosion, EPA believes that multiple barriers against corrosion-related failures,

including construction and monitoring requirements, are necessary in order to protect USDWs from

endangerment.

Several laboratory studies and a limited number of field studies have investigated and characterized

the effects of carbonic acid on well materials. Laboratory studies (e.g., Kutchko et al., 2007;

Kutchko et al., 2008; Akervoll, 2005) consistently identify alterations (typically carbonation) of

cement as the result of interactions between cement and CO2-saturated brine. 

Currently, there are only a few analyses of cement from wells that have been in prolonged contact

with CO2 in actual field (down-hole) conditions. Evaluation of cement from a well at the Scurry

Area Canyon Reef Operators Committee (SACROC) site showed alteration, but did not show

degradation that compromised the structural integrity of the cement (Carey et al., 2007). In another

study, cement samples were collected and analyzed from a CO2 production well in a natural CO2

reservoir in Colorado exposed to a CO2-water down-hole environment for 30 years (Crow et al.,

2008). The study found evidence of reaction between the CO2-rich water and the cement. 

Oil industry research also addresses the effects of corrosion of steel tubing and pipes. Lopez et al.

(2003) noted that 60 percent of oilfield failures are related to the effects of carbonic acid from

produced brines on carbon and low alloy steels. A report by CO2 Norway (2004) notes that in some

CO2 ER floods in the Permian Basin of Texas, bare carbon steel tubing has been used successfully. 

Laboratory investigation of cement alteration/degradation is an ongoing research area. Few fieldbased studies have been completed to date. Although the laboratory and field studies currently

available suggest that corrosion problems may not be serious, there is not enough data to rule out
potential corrosion problems of steel components of injection wells. Given the anticipated long

lifespan of a Class VI well and the difficulties that would be associated with a corrosion-related well

failure, EPA believes that corrosion monitoring in the down-hole environment is justified in order to

protect USDWs from endangerment.

Commenter Name: John King Letter ID: 0211

Commenter Organization: Shell Exploration and Production Company

(SEPCo)

Comment ID:

22774

Comment: 3. Corrosion Monitoring 

As already discussed, CO2 is not corrosive in the absence of water and there is 

no basis to assume that carbon sequestration wells will typically or even often 

be injecting corrosive fluids. A general requirement for corrosion monitoring is 

therefore unnecessary and inappropriate. 

Response: EPA disagrees with the commenter's assertion that corrosion monitoring is unnecessary

or excessive. CO2 in the presence of water (including water with NOx, SOx, and H2S impurities)

can be corrosive to well materials and cements. Thus, although a CO2 stream may be dry, the

potential for corrosion of well materials down-hole, where the injectate can potentially mix with

water in the target formation, must be considered. 

Several laboratory studies and a limited number of field studies have investigated and characterized

the effects of carbonic acid on well materials. Laboratory studies (e.g., Kutchko, et al. 2007;

Kutchko, et al. 2008; Akervoll, 2005) consistently identify alterations (typically carbonation) of

cement as the result of interactions between cement and CO2-saturated brine. 

Currently, there are only a few analyses of cement from wells that have been in prolonged contact

with CO2 in actual field (down-hole) conditions. Evaluation of cement from a well at the Scurry

Area Canyon Reef Operators Committee (SACROC) site showed alteration, but did not show

degradation that compromised the structural integrity of the cement (Carey, et al. 2007). In another

study, cement samples were collected and analyzed from a CO2 production well in a natural CO2

reservoir in Colorado exposed to a CO2-water down-hole environment for 30 years (Crow, et al.

2008). The study found evidence of reaction between the CO2-rich water and the cement. 

Oil industry research also addresses the effects of corrosion of steel tubing and pipes. Lopez, et al.

(2003) noted that 60 percent of oilfield failures are related to the effects of carbonic acid from

produced brines on carbon and low alloy steels. A report by CO2 Norway (2004) notes that in some

CO2 ER floods in the Permian Basin of Texas, bare carbon steel tubing has been used successfully. 

Laboratory investigation of cement alteration/degradation is an ongoing research area. Few fieldbased studies have been completed to date. Although the laboratory and field studies currently

available suggest that corrosion problems may not be serious, there is not enough data to rule out

potential corrosion problems of steel components of injection wells. Given the anticipated long

lifespan of a Class VI well and the difficulties that would be associated with a corrosion-related well

failure, EPA believes that corrosion monitoring in the down-hole environment is justified in order to

protect USDWs from endangerment.

Comment Code: 4300 2.4.4 Injection Depth 
Individual Comments

Commenter Name: Wendy Jacobs Letter ID: 0183

Commenter Organization: Harvard Law School Environmental Law and Policy

Center

Comment ID:

25166

Comment: VI. EPA Should Rank Sites With GS Capability Based On Their Specific Leakage

Risk Profiles.

In the preamble to the proposed regulation, EPA states that it is soliciting

comment on:

(1) Whether CO2 injection should be allowed into an injection zone above the

lowermost USDW, when the Director determines that geologic conditions (e.g.,

thousands of feet of intervening formations between the injection zone and the

overlying and/or underlying USDWs) exist that will prevent fluid movement into

adjacent USDWs; and

(2) Whether aquifer exemptions should be allowed for the purpose of Class VI

injection, and under what conditions should such aquifer exemptions be approved.

73 Fed. Reg. at 43,511-12 

EPA suggests that its rationale for allowing the injection of CO2 above the

lowermost aquifer is to increase the available storage capacity for CO2. See id.

at 43,512. In other contexts (e.g., for Class I injection wells), however, EPA

has refrained from compromising USDWs to increase the available storage capacity

for fluids. The Agency has not presented a case for a departure from that

general principle here.

The WRI Guidelines avoid explicit use of the terms "exemption" or "injection

above the lowermost aquifer" and instead propose guidelines for site selection

and characterization of storage capacity. WRI GUIDELINES at 91. Building on the

WRI’s guidelines and on further research, the EPA should rank sites with

geological storage capacity depending on the specific risk profile of CO2

leakage to lower geological formations and other relevant factors. The WRI

Guidelines suggest the following "General Guidelines for Site Characterization

and Selection":

1. Potential storage reservoirs should be ranked using a set of criteria

developed to minimize leakage risks. Future work is needed to clarify such

ranking criteria.

2. Low-risk sites should be prioritized for early projects. 

3. As required by regulation, storage reservoirs should not be freshwater
aquifers or potential underground sources of drinking water.

4. Confining zone(s) should be present that possess characteristics sufficient

to prevent the injected or displaced fluids from migrating to drinking water

sources or the surface.

5. Site-specific data should be collected and used to develop a subsurface

reservoir model to predict/simulate the injection over the lifetime of the

storage project and the associated project footprint. These simulations should

make predictions that can be verified by history-matching within a relatively

short period of time after initial CO2 injection or upon completion of the first

round of wells. The reservoir model and simulations should be updated

periodically as warranted and agreed with regulators.

6. Saline formations and mature oil and gas fields should be considered for

initial projects. Other formations, such as coal seams, may prove viable for

subsequent activity with additional research.

WRI GUIDELINES at 91. 

According to the WRI Guidelines, EPA would first authorize GS at sites with low

risk. However, as more GS projects are deployed and the availability of low

risk sites decreases (eventually, perhaps, to zero), EPA would then determine

whether to authorize GS at higher-risk sites. In that case, ELPC and ETIP

suggest that EPA consider conditioning its approval on a demonstration by the

owner or operator that it is technically feasible to treat groundwater that may

become contaminated as a result of the GS activity if needed to supply public or

smaller water systems at a future date. EPA could also require the owner or

operator to provide financial assurance to cover the costs of such treatment.

Response: EPA disagrees that a ranking of sites is appropriate, or that permitting sites on the basis

of whether treatment of ground water contamination is feasible. EPA believes that requiring

appropriate site characterization by the owner or operator, as required under §146.82 and providing

an appropriate degree of flexibility to the Director to evaluate site-specific geologic data will afford

the greatest protection of USDWs from endangerment. EPA believes that it is important for the

Director to have as much site-specific information as possible in order to make an informed decision

to permit injection for GS at a specific site. 

EPA believes that there are limited circumstances where injection above the lowermost USDW can

be performed in a manner that protects USDWs, as long as appropriate protections are in place. The

final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver of the

Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. It establishes: 1) requirements specifying information that owners or operators must

submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for public

notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class
VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. The final rule also establishes limited circumstances under which

expansions of the areal extent of aquifer exemptions may be granted for owners or operators of

Class II EOR/EGR wells transitioning to Class VI injection for GS. Additionally, the rule does not

categorically preclude or prohibit injection into any type of formation. 

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Scott Anderson Letter ID: 0520

Commenter Organization: Environmental Defense Fund Comment ID: 21419

Other EPA Comment Codes and Descriptions: 1270 1.1.2 Comments on other rules/issues 

Comment: And then secondly, I would like to agree with American Waterworks Association 

about the point that changing technical abilities for cleaning up water as well 

as increasing water demand does make it important that we not consider ten 

thousand parts per million to be set in stone. 

Response: EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. Specifically, the Director must consider whether alternative

injection sites are available; community needs, demands, and supply from drinking water resources;

planned needs, potential and/or future use of USDWs and non-USDWs in the area; and a plan for

securing alternative resources or treating USDW formation waters in the event of contamination

related to the Class VI injection activity.

EPA is not changing the USDW definition; changing the definition of a USDW is outside the scope

of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as required under the

SDWA, by establishing regulations to ensure the safe injection of CO2 for long-term storage.

Comment Code: 4320 2.4.4.1 Injection beneath the lowermost formation containing a USDW 

Individual Comments

Commenter Name: Carl Carlsson Letter ID: 0131

Commenter Organization: SUEZ Energy Generation NA, LLC Comment ID: 21533

Comment: Injection Well Operating Requirements 

SEGNA agrees with EPA's proposal to allow Directors to exempt Underground 

Sources of Drinking Water (USDWs) below the injection zone, and allow injection 

below the lowermost non-exempted USDW. SEGNA also supports the 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for
Class VI wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI wells; that is,

aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. For additional information on aquifer exemptions for Class VI wells, please see the

final rule and preamble, as well as EPA's responses to comments on the Notice of Data Availability

and Request for Comment.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23413

Other EPA Comment Codes and Descriptions: 4430 2.4.4.3.3 Injection into coal seams above

USDWs (seeking comment) 

Comment: Class VI CO2 GS wells. APPA offers no opinions on injection of CO2 into coal 

seams. APPA defers to the American Water Works Association regarding the 

questions pertaining to whether above or below the lowermost USDW. The EPA asked 

Response: EPA believes that there are limited circumstances where injection above the lowermost

USDW can be performed in a manner that protects USDWs from endangerment, as long as

appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Wendy Jacobs Letter ID: 0183

Commenter Organization: Harvard Law School Environmental Law and Policy

Center

Comment ID:

25167

Comment: A. CO2 Injection Above The Lowermost USDW 

The proposed regulation prohibits GS above the lowermost USDW. 73 Fed. Reg. at

43,535 (proposed 40 C.F.R. § 146.5(f)) (defining Class VI wells as "[w]ells used

for geologic sequestration of carbon dioxide beneath the lowermost formation

containing an underground source of drinking water (USDW)"). EPA explains in

the preamble that this safeguard is "a very important protective component of

the UIC program. Placing distance between the point of injection and USDWs

allows for the necessary confining and buffer formations, and further provides

for opportunity for additional monitoring to detect any excursions from the
intended injection zone." Id. at 43,511.

The regulations for Class I hazardous and non-hazardous waste injection wells

contain a similar prohibition against injection above a lowermost USDW. See id.

at 43,511; U.S. EPA, CLASS I UNDERGROUND INJECTION CONTROL PROGRAM: STUDY

OF THE

RISKS ASSOCIATED WITH CLASS I UNDERGROUND INJECTION WELLS 2 (March 2001)

("By

definition, Class I wells inject industrial or municipal wastewater beneath the

lowermost USDW."). EPA explains that this restriction is one of "multiple

barriers" to a release of injected fluid into a USDW. Id. at 40. It is unclear,

however, why lowermost USDWs should be afforded less protection from GS,

especially in light of the anticipated long life spans of GS projects.

Given the emerging state of technology associated with GS and the lack of data

available regarding the likely behavior of injected CO2 over hundreds or

thousands of years, EPA should at minimum ensure that multiple safeguards are in

place before USDWs are put at risk. Indeed, EPA itself admits that it currently

lacks data to demonstrate if injection above or between USDWs is appropriate and

protective of USDWs. 73 Fed. Reg. at 43,512. Nonetheless, EPA is considering

giving the Director discretion to allow CO2 injection above the lowermost USDW

when he or she determines that geologic conditions such as thousands of feet of

intervening formations between the injection zone and the overlying and/or

underlying USDWs exist that will prevent fluid movement into adjacent USDWs. Id.

EPA anticipates that such discretion would allow GS "in specific geologic

settings where the depth of the USDWs may preclude GS, make GS technically

challenging, or significantly limit CO2 storage capacity." Id. (suggesting that

"[a]n example where such injection may be appropriate presents itself in areas

such as the Williston and Powder River Basins in Wyoming, North Dakota, and

South Dakota, where receiving formations (formations with large CO2 storage

capacity) for GS have been identified above the lowermost USDW and where there

may be thousands of feet of rock strata between the injection zone and the

overlying and underlying USDWs").

Before allowing such injections, EPA should first carry out further research and

rank sites with geological storage capacity according to specific factors such

as risk of leakage of impure streams of CO2 to lowermost geological formations,

distance between the injection zone and the lowermost USDW, composition of the

rock strata that will prevent contamination of underground reservoirs, and the

specific characteristics of the aquifer such as the quantity of water and the

depth of the aquifer.

Response: As described above, EPA disagrees that a ranking of sites is appropriate, and believes

that decisions regarding the suitability of a proposed site should be made based on site-specific data.

EPA agrees that protecting USDWs from endangerment must be a top priority. The Agency believes

that there are limited circumstances where injection above the lowermost USDW can be performed

in a manner that protects USDWs, as long as appropriate protections are in place. The final GS rule

at §146.95 establishes a process by which owners or operators can seek a waiver of the Class VI
injection depth requirements for injection into non-USDW formations above and/or between

USDWs. 

EPA believes that the requirements at §146.95 will ensure USDW protection while providing

flexibility to UIC Program Directors and owners or operators who undertake CO2 injection for GS.

The Agency believes this approach: 1) responds to concerns about local and regional geologic

storage capacity limitations imposed by the proposed injection depth requirements; 2) allows for a

more site-specific assessment of injection depth for GS projects; 3) accommodates injection into

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or

between USDWs when appropriate and where it can be demonstrated that USDWs will be protected;

and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to

addressing injection depth variability through a waiver process responds to concerns about future

drinking water resource availability and the need to ensure that high quality water remains available

in sufficient quantities to supply drinking water needs. For additional information on the waiver

approach, please see the final rule and preamble, as well as EPA's responses to comments on the

Notice of Data Availability and Request for Comment.

Commenter Name: Thomas Curtis Letter ID: 0204

Commenter Organization: American Water Works Association (AWWA) Comment ID: 22183

Other EPA Comment Codes and Descriptions: 1610 1.3.1 Risks to USDWs 

Comment: - The protection of the lowermost USDWs is of critical importance, and the 

location of these USDWs should be the primary factor in determining if a 

geosequestration project can be located in the same area. 

Response: The Agency agrees that drinking water is an important resource to protect. The primary

goal of the UIC Program under the SDWA is to protect USDWs from endangerment. Consistent

with SDWA §1422, the UIC program provides that no injection shall be authorized if it results in the

movement of fluid containing any contaminant into USDWs, if the presence of that contaminant may

cause a violation of any primary drinking water regulation or may adversely affect the health of

persons as specified in §144.12.

The GS rule requires operators to submit extensive information about the site, including the geologic

characteristics of the injection and confining zones, to demonstrate that the injected CO2 will remain

within the target formation. The Director must consider this information and the potential impact of

the GS project on any USDWs when determining whether GS is acceptable at a given site. 

In many cases, UIC Directors will have extensive knowledge of which areas are suitable for GS, but

clarifies that it is the responsibility of Class VI permit applicants to demonstrate the suitability of a

particular site or formation. It is the responsibility of the Director to evaluate the information

collected and submitted by the owner or operator to determine whether a permit for GS at the site is

appropriate.

EPA agrees that protecting USDWs from endangerment must be a top priority. The Agency believes

that there are limited circumstances where injection above the lowermost USDW can be performed

in a manner that protects USDWs, as long as appropriate protections are in place. The final GS rule

at §146.95 establishes a process by which owners or operators can seek a waiver of the Class VI

injection depth requirements for injection into non-USDW formations above and/or between

USDWs. The waiver approach requires the submission of extensive, site-specific information (in

conjunction with the permit application submission) to demonstrate that injection of CO2 into a non-
USDW that is above or between USDWs can be done in a manner that is protective of USDWs. It

establishes: 1) requirements specifying information that owners or operators must submit, and

Directors must consider, in consultation with PWSS Directors; 2) procedures for public notice of a

waiver application and for Director-Regional Administrator communication; 3) the waiver issuance

process; and, 4) additional requirements that apply to owners or operators of Class VI wells granted

a waiver of the injection depth requirements to ensure USDW protection above and below the

injection zone. 

EPA believes that the requirements at §146.95 will ensure USDW protection while providing

flexibility to UIC Program Directors and owners or operators who undertake CO2 injection for GS.

The Agency believes this approach: 1) responds to concerns about local and regional geologic

storage capacity limitations imposed by the proposed injection depth requirements; 2) allows for a

more site-specific assessment of injection depth for GS projects; 3) accommodates injection into

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or

between USDWs when appropriate and where it can be demonstrated that USDWs will be protected;

and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to

addressing injection depth variability through a waiver process responds to concerns about future

drinking water resource availability and the need to ensure that high quality water remains available

in sufficient quantities to supply drinking water needs. For additional information on the waiver

approach, please see the final rule and preamble, as well as EPA's responses to comments on the

Notice of Data Availability and Request for Comment.

Commenter Name: John Corra Letter ID: 0205

Commenter Organization: Wyoming Department of Environmental Quality

(DEQ)

Comment ID:

22195

Other EPA Comment Codes and Descriptions: 4460 2.4.4.4.1 Comments in favor of allowing

aquifer exemptions in certain circumstances 

Comment: b. Furthermore, we support providing Directors the flexibility and discretion 

to: 

i. Exempt all USDWs below the injection zone (if necessary to meet a requirement 

that injection is only allowed beneath the deepest USDW). 

ii. Exempt aquifers for the purpose of CO2 injection in accordance with the 

requirements of 40 CFR 144.7. 

iii. Exempt aquifers for the purpose of CO2 injection in accordance with the 

requirements of 40 CFR 146.4. 

c. In the event that aquifer exemptions are not feasible, we urge the US EPA to 

allow CO2 injection into aquifers previously exempted for Class I and Class II 

injection operations, provided that the operator obtains a new aquifer exemption 

for the purpose of GS. 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for
GS wells in the final GS rule.

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. 

EPA adds that the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells.

Aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. Aquifer exemption expansions are limited to Class II EOR/EGR wells

transitioning to Class VI injection for GS. The aquifer exemption requirements in the final rule

provide flexibility and afford owners or operators an opportunity to assess and select a suitable GS

site while also preserving USDWs (i.e., formations/aquifers afforded SDWA protection). Class VI

owners or operators granted expansions of existing Class II EOR/EGR aquifer exemptions for GS

projects must meet all of the tailored requirements for GS wells in the final GS rule.

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Comment Code: 4322 2.4.4.1.1 Comments in favor of requiring injection below the lowermost

USDW 

Individual Comments

Commenter Name: John Stormon Letter ID: 0123

Commenter Organization: Washington State Dept. of Ecology Comment ID: 23000

Comment: Injection Zones: Geologic sequestration should only be allowed beneath the 

lowest USDW. Protecting USDW is the most important aspect of the UIC program for 

the geologic sequestration of carbon dioxide. As proposed in the federal rules 

for geologic sequestration these sites should all be kept beneath the lowest 

USDW, to prevent the degradation of future ground water resources that we are 

likely to need in the coming centuries. 

Response: EPA agrees that protecting USDWs from endangerment must be a top priority. The

Agency believes that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. It establishes: 1) requirements specifying information that owners or operators must

submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for public

notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class

VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. The final rule also establishes limited circumstances under which

expansions of the areal extent of aquifer exemptions may be granted for owners or operators of
Class II EOR/EGR wells transitioning to Class VI injection for GS. Additionally, the rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that the requirements at §146.95 will ensure USDW protection while providing

flexibility to UIC Program Directors and owners or operators who undertake CO2 injection for GS.

The Agency believes this approach: 1) responds to concerns about local and regional geologic

storage capacity limitations imposed by the proposed injection depth requirements; 2) allows for a

more site-specific assessment of injection depth for GS projects; 3) accommodates injection into

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or

between USDWs when appropriate and where it can be demonstrated that USDWs will be protected;

and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to

addressing injection depth variability through a waiver process responds to concerns about future

drinking water resource availability and the need to ensure that high quality water remains available

in sufficient quantities to supply drinking water needs. For additional information on the waiver

approach, please see the final rule and preamble, as well as EPA's responses to comments on the

Notice of Data Availability and Request for Comment.

Commenter Name: Jill D. Jonas Letter ID: 0135

Commenter Organization: Wisconsin Dept. of Natural Resources (WDNR) Comment ID: 21666

Comment: Limiting CO2 Injection to Formations below the Lowermost USDW 

Protecting the quality of groundwater resources that may be used as sources of 

drinking water must continue to be the highest priority for all regulations 

promulgated under the authority of the UIC program and the federal Safe Drinking 

Water Act. WDNR supports limiting CO2 injection to geologic formations which lie 

beneath the lowermost USDW and, more specifically, only to those deep formations 

that have also been determined by means of a detailed geological assessment to 

pose the least potential for endangering drinking water supplies. 

There may be a number of other suitable geologic formations for GS that are 

situated above the lowermost USDW (e.g. basalts, salt domes, shales, coal seams, 

etc.); however, these formations tend to be more limited in their geographic 

distribution and the economic and technological viability of these formations as 

GS sites is still in question. Additional study of GS in these settings can be 

accomplished on a case-by-case basis using the UIC program's existing authority 

to approve experimental Class V injection wells. 

For the present, limiting large-scale CO2 injections to formations that lie 

beneath the lowermost USDW while continuing to investigate CO2 injection above 

the lowermost USDW using the existing rules for Class V experimental wells will 

not delay the deployment of this climate change mitigation technology. 

Response: EPA agrees that protecting USDWs from endangerment must be a top priority. The

Agency believes that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective
of USDWs. It establishes: 1) requirements specifying information that owners or operators must

submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for public

notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class

VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. 

EPA believes that the requirements at §146.95 will ensure USDW protection while providing

flexibility to UIC Program Directors and owners or operators who undertake CO2 injection for GS.

The Agency believes this approach: 1) responds to concerns about local and regional geologic

storage capacity limitations imposed by the proposed injection depth requirements; 2) allows for a

more site-specific assessment of injection depth for GS projects; 3) accommodates injection into

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or

between USDWs when appropriate and where it can be demonstrated that USDWs will be protected;

and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to

addressing injection depth variability through a waiver process responds to concerns about future

drinking water resource availability and the need to ensure that high quality water remains available

in sufficient quantities to supply drinking water needs. For additional information on the waiver

approach, please see the final rule and preamble, as well as EPA's responses to comments on the

Notice of Data Availability and Request for Comment.

Regarding the suggestion to allow experimental GS wells to continue to operate under Class V, EPA

anticipates that some owners or operators will apply for Class V experimental technology permits for

injection into formations including shallow basalts, coal seams, salt caverns and shales. These

formations may or may not be located above the lowermost USDW or between USDWs. To

facilitate experimental injection for GS and to increase understanding of injection into these

formation types, the Agency is amending the Class V experimental technology guidance. The

guidance will be available on EPA's web site, at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. EPA acknowledges that the Class

V experimental technology well sub-classification may be appropriate for these projects, provided

they are experimental in nature. EPA expects that, following the final GS rule, a limited number of

experimental injection projects testing GS technology will continue. EPA anticipates that these

projects will be small-scale and involve limited CO2 volumes. However, if these projects become

larger scale and are no longer experimental, they will need to be permitted as Class VI wells. The

construction, operation or maintenance of any non-experimental Class V GS well is prohibited, at

§144.15.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22578

Other EPA Comment Codes and Descriptions: 4410 2.4.4.3.1 Comments in favor of allowing

injection above/between USDWs in certain circumstances 

Comment: Preamble Questions: The location and proximity of other formations to USDWs may 

preclude their use for GS. EPA seeks comment on prohibiting injection into such 

formations if they are above the lowermost USDW. EPA Notice 54. 

NGWA Response: NGWA supports the general prohibition against injections above 

the lowermost USDW. An exemption process should be available to review and 

consider those specific situations where injection cannot be done, or is being 

proposed not to be done, below the lowermost USDW 
Response: EPA agrees that protecting USDWs from endangerment must be a top priority. The

Agency believes that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. 

The waiver approach requires the submission of extensive, site-specific information (in conjunction

with the permit application submission) to demonstrate that injection of CO2 into a non-USDW that

is above or between USDWs can be done in a manner that is protective of USDWs. It also

establishes procedures for public notice of a waiver application and for Director-Regional

Administrator communication and requirements specifying information that owners or operators

must submit, and Directors must consider, in consultation with PWSS Directors.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22585

Other EPA Comment Codes and Descriptions: 4410 2.4.4.3.1 Comments in favor of allowing

injection above/between USDWs in certain circumstances 

Comment: Preamble Questions: EPA is soliciting comment on whether CO2 injection should be 

allowed into an injection zone above the lowermost USDW, when the Director 

determines that geologic conditions (e.g., thousands of feet of intervening 

formations between the injection zone and the overlying and/or underlying USDWs) 

exist that will prevent fluid movement into adjacent USDWs. EPA Notice 93. 

NGWA Response: NGWA supports the general prohibition against injections above 

the lowermost USDW. An exemption process should be available to review and 

consider those specific situations where injection cannot be done, or is being 

proposed not to be done, below the lowermost USDW 

Proposed Rule: 144.6(f) 

Comment: NGWA supports the general prohibition against injections above the 

lowermost USDW. An exemption process should be made available to review and 

consider those specific situations where injection cannot be done, or is being 

proposed not to be done, below the lowermost USDW. 

Rationale: NGWA understands that there may be portions of the country that will 

not have adequate storage zones below the lowermost USDW. In these areas, the 

Association believes that storage above the lowermost USDW may be allowed on a 

site specific basis based on director discretion assuming that all other 

conditions are met. 

Response: As described above, the final GS rule at §146.95 establishes a process by which owners

or operators can seek a waiver of the Class VI injection depth requirements for injection into nonUSDW formations above and/or between USDWs. The waiver approach requires the submission of

extensive, site-specific information to demonstrate that injection of CO2 into a non-USDW that is

above or between USDWs can be done in a manner that is protective of USDWs.
Commenter Name: Richard Driggans Letter ID: 0145

Commenter Organization: Tennessee Valley Authority Comment ID: 23153

Comment: 4. Injection Depth in Relation to USDWs - The proposed rule requested comment on 

alternative approaches that would allow injection between and/or above the 

lowermost USDW, and thus potentially allow for more areas to be available for GS 

while preventing USDW endangerment. Limiting CO2 GS to geologic units below the 

lowest USDW is prudent and reasonable. Prohibiting injection between and/or 

above the lowermost USDW is essential to protecting valuable drinking water 

sources by avoiding unnecessary siting and operational risks. Once experience 

Response: EPA agrees that protecting USDWs from endangerment must be a top priority. The

Agency believes that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. It establishes: 1) requirements specifying information that owners or operators must

submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for public

notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class

VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. 

EPA believes that the requirements at §146.95 will ensure USDW protection while providing

flexibility to UIC Program Directors and owners or operators who undertake CO2 injection for GS.

The Agency believes this approach: 1) responds to concerns about local and regional geologic

storage capacity limitations imposed by the proposed injection depth requirements; 2) allows for a

more site-specific assessment of injection depth for GS projects; 3) accommodates injection into

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or

between USDWs when appropriate and where it can be demonstrated that USDWs will be protected;

and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to

addressing injection depth variability through a waiver process responds to concerns about future

drinking water resource availability and the need to ensure that high quality water remains available

in sufficient quantities to supply drinking water needs. For additional information on the waiver

approach, please see the final rule and preamble, as well as EPA's responses to comments on the

Notice of Data Availability and Request for Comment.

Commenter Name: Richard Driggans Letter ID: 0145

Commenter Organization: Tennessee Valley Authority Comment ID: 23157

Other EPA Comment Codes and Descriptions: 4410 2.4.4.3.1 Comments in favor of allowing

injection above/between USDWs in certain circumstances 

Comment: sources by avoiding unnecessary siting and operational risks. Once experience 

is gained with the long-term behavior and geologic containment of CO2, injection 

depths above the lowermost USDW may be considered appropriate on a site-specific 

basis (e.g., where storage depth would be sufficient for maintaining CO2 in a 

supercritical state and separate from USDWs). 
Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

The waiver approach requires the submission of extensive, site-specific information (in conjunction

with the permit application submission) to demonstrate that injection of CO2 into a non-USDW that

is above or between USDWs can be done in a manner that is protective of USDWs. The

requirements are designed to ensure that the owner or operator, the Director, and the Regional

Administrator consider, on a site specific basis, the implications, benefits, and challenges associated

with GS and ensuring water availability and USDW protection. 

It establishes: 1) requirements specifying information that owners or operators must submit, and

Directors must consider, in consultation with PWSS Directors; 2) procedures for public notice of a

waiver application and for Director-Regional Administrator communication; 3) the waiver issuance

process; and, 4) additional requirements that apply to owners or operators of Class VI wells granted

a waiver of the injection depth requirements to ensure USDW protection above and below the

injection zone. EPA believes that these requirements will ensure USDW protection while providing

flexibility to UIC program Directors and owners or operators who undertake CO2 injection for GS.

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Bonnie Lovelace Letter ID: 0152

Commenter Organization: Montana Department of Environmental Quality

(MDEQ)

Comment ID:

22116

Comment: 15. EPA seeks comment on whether carbon dioxide injection should be allowed above 

the lowermost underground source of drinking water (USDW) under certain 

conditions. MDEQ suggests that with all the safety considerations already 

described in this rule proposal and the possible environmental impacts due to 

migration of contaminants and mobilization of whole rock content, injections 

should be limited to beneath the lowermost USDW. 

Response: EPA believes that there are limited circumstances where injection above the lowermost

USDW can be performed in a manner that protects USDWs, as long as appropriate protections are in

place. The final GS rule at §146.95 establishes a process by which owners or operators can seek a

waiver of the Class VI injection depth requirements for injection into non-USDW formations above

and/or between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. It establishes: 1) requirements specifying information that owners or operators must

submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for public

notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class

VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. 
For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23644

Other EPA Comment Codes and Descriptions: 2100 1.6 Target Geologic Formations for GS 

Comment: - Injection of carbon dioxide and construction of injection wells should not be 

allowed in or near sole source aquifers, coal seams, earth-quake prone areas, or 

above the lowermost USDWs; 

Response: EPA clarifies that the GS rule does not preclude injection into any non-USDWs nonUSDW formations, provided the site-suitability requirements in the GS rule are met. The purpose of

the GS rule is to ensure protection of USDWs from endangerment, and the rule requires that owners

or operators demonstrate that wells are sited in suitable systems with geologic formations to receive

and confine injected CO2, required at §146.83 of the GS rule. If an owner or operator can

demonstrate to the Director's satisfaction that GS in coal seams, basalts, salt domes, or shales can be

accomplished in a manner that protects USDWs and meets all of the requirements of the GS rule, the

project may be permitted as a Class VI well.

In response to the comment that GS should not be allowed in areas with high-risk for a seismic

event, EPA clarifies that the GS rule does not allow GS to be performed in seismically active areas

and requires that operators must submit information about the seismic history of and seismic sources

near a proposed GS site, as required at §146.82(a)(3)(v). This information, along with other required

submissions, will be evaluated by the Director, who will determine the suitability of a potential

project site for GS. 

Additionally, the GS rule, at 146.82(a)(5) requires prospective owners or operators to submit

information on all USDWs, which would include sole source aquifers within the AoR. Based on that

information the Director must consider the potential impact of the GS project on all USDWs,

including any sole source aquifers when determining whether GS is acceptable at a given site. EPA

clarifies that a state’s Class VI primacy program may be more stringent then the federal

requirements. For example, a state has the discretion to ban GS projects from taking place in

formations or areas that affect sole source aquifers. EPA anticipates that state permitting authorities

are in the best position to make determinations about the appropriateness of a particular site based on

all available information, including drinking water supply needs.

As described above, the Agency believes that there are limited circumstances where injection above

the lowermost USDW can be performed in a manner that protects USDWs, as long as appropriate

protections are in place. The final GS rule at §146.95 establishes a process by which owners or

operators can seek a waiver of the Class VI injection depth requirements for injection into nonUSDW formations above and/or between USDWs. 

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23678

Other EPA Comment Codes and Descriptions: 2166 1.6.3.2 Comments opposing injection into

unmineable coal seams 

Comment: Category: USDW Location 
EPA Request for Comment: EPA is proposing to preclude the injection of CO2 for 

long-term storage into coal seams where they are above the lowermost USDW. EPA 

requests comment on this proposed prohibition. EPA Notice 43503. 

AWWA Response: AWWA recommends that EPA preclude the injection of carbon dioxide 

into coal seams located above the lowermost USDWs. First and foremost, AWWA is 

adamantly opposed to the injection of carbon dioxide into any storage formation 

not located beneath the lowermost USDW. If a utility ever desired to use the 

USDW as a water resource, they would have to drill through the carbon dioxide 

plume, thus creating a pathway for carbon dioxide to potentially migrate out of 

the confining layer and into nearby aquifers. This could cause contamination of 

USDWs located above the coal seam, and result in significant remediation 

activities for a water utility. Second, little research has been conducted to 

determine the specific impacts that storage of carbon dioxide would have on coal 

seams. Much of the research that has been performed to date has been on either 

carbon dioxide storage in saline reservoirs or in depleted oil/gas fields. AWWA 

recommends that at this point in time, EPA preclude the injection of carbon 

dioxide into all coal seams, no matter where they are located in the subsurface. 

This regulation was not designed for coal seams to be used as carbon dioxide 

storage reservoirs. Therefore, AWWA recommends that any wells constructed for 

the injection of carbon dioxide into coal seams wells be permitted under the 

Class V experimental wells until the potential impacts of coal seam carbon 

dioxide sequestration on USDWs are better understood. 

Response: The final GS rule does not preclude injection into unmineable coal seams (or any nonUSDW formation type) provided owners or operators can demonstrate that GS can be performed in

a manner that protects USDWs from endangerment as required under today’s final rule. 

EPA recognizes that GS in unmineable coal seams has been the subject of less research than saline

formations or depleted oil and gas reservoirs. However, EPA has examined select field projects

involving injection into unmineable coal seams, including the Pump Canyon Site, near Archuleta,

New Mexico. In the Notice of Data Availability and Request for Comment, EPA described research

at the Pump Canyon site where the Southwest Partnership is studying CO2 injection into deep,

unmineable coal seams and performing a "seal analysis" of the ability of the Kirtland Formation to

act as a barrier to the movement of CO2 or other reservoir fluids. EPA continues to follow this

project, recently completed projects, and ongoing GS projects injecting into unmineable coal seams.

Other coal seam injection projects are underway through the RCSPs in the Illinois Basin, Black

Warrior Basin, and Central Appalachian Basin.

EPA acknowledges that there may be risks associated with GS into coal seams. For this reason, the

Agency is using an adaptive approach to regulate GS injection. The Agency anticipates that in the

near-term, most GS in unmineable coal seams will continue to be experimental. Such projects may

be permitted as Class V experimental technology wells if they are of an experimental nature (i.e., to

test GS technologies and collect data).EPA will collect and review project data on early GS projects,

including those that inject into various formation types, to determine whether the appropriate amount

and types of information and documentation are being collected. EPA plans, every six years, to

collect and review data on GS projects to determine whether the appropriate amount and types of

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

the requirements are appropriate or necessary.
EPA clarifies that the final rule requires that injection for GS be into non-USDWs below the

lowermost USDW; however, owners or operators may apply for a waiver from this requirement, as

described in §146.95. For more information, see the discussion of waivers in the preamble to the

final rule.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23679

Comment: EPA Request for Comment: EPA is soliciting comment on whether CO2 injection 

should be allowed into an injection zone above the lowermost USDW, when the 

Director determines that geologic conditions (e.g., thousands of feet of 

intervening formations between the injection zone and the overlying and/or 

underlying USDWs) exist that will prevent fluid movement into adjacent USDWs. 

EPA Notice 43512. 

AWWA Response: As previously stated, AWWA is adamantly opposed to the injection 

of carbon dioxide into any storage formation not located beneath the lowermost 

USDW. If a utility ever desired to use the lowermost USDW as a water resource, 

they would have to drill through the carbon dioxide plume, thus creating a 

pathway for carbon dioxide to potentially migrate out of the confining layer and 

into nearby aquifers. This could cause contamination of USDWs located above the 

storage aquifer, and result in significant remediation activities for a water 

utility. AWWA recommends that EPA include a section in the final regulation 

prohibiting the injection of carbon dioxide into any formation located above the 

lowermost USDW. 

Response: As described above, EPA agrees that protecting USDWs from endangerment must be a

top priority. The Agency believes that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs, as long as appropriate

protections are in place. The final GS rule at §146.95 establishes a process by which owners or

operators can seek a waiver of the Class VI injection depth requirements for injection into nonUSDW formations above and/or between USDWs. 

EPA believes that the requirements at §146.95 will ensure USDW protection while providing

flexibility to UIC Program Directors and owners or operators who undertake CO2 injection for GS.

EPA’s approach to addressing injection depth variability through a waiver process responds to

concerns about future drinking water resource availability and the need to ensure that high quality

water remains available in sufficient quantities to supply drinking water needs. For additional

information on the waiver approach, please see the final rule and preamble, as well as EPA's

responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Diane VanDe Hei Letter ID: 0213

Commenter Organization: Association of Metropolitan Water Agencies

(AMWA)

Comment ID:

22942

Comment: determine the impacts of CO2 storage on coal seams. Furthermore, AMWA opposes 

the injection into any formation above the lowermost existing or potential USDW 

and recommends that EPA only allow for the injection of CO2 into formations 

below the lowermost existing or potential USDW. Congress intended the UIC 

program to protect sources and potential sources of drinking water from 
contamination: "Underground injection endangers drinking water sources if such 

injection may result in the presence in underground water which supplies or can 

reasonably be expected to supply any public water system of any contaminant, and 

if the presence of such contaminant may result in such system’s not complying 

with any national primary drinking water regulation or may otherwise adversely 

affect the health of persons." SDWA § 1421(d)(2); 42 U.S.C. § 300h(d)(2). 

AMWA believes that allowing the injection of CO2 above a USDW would endanger the 

USDW by providing a pathway for CO2 to contaminate a drinking water source, 

especially if a well was constructed through a CO2 plume. 

Response: EPA agrees that protecting USDWs from endangerment must be a top priority. The

Agency believes that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. It establishes: 1) requirements specifying information that owners or operators must

submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for public

notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class

VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. 

EPA believes that the requirements at §146.95 will ensure USDW protection while providing

flexibility to UIC Program Directors and owners or operators who undertake CO2 injection for GS.

The Agency believes this approach: 1) responds to concerns about local and regional geologic

storage capacity limitations imposed by the proposed injection depth requirements; 2) allows for a

more site-specific assessment of injection depth for GS projects; 3) accommodates injection into

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or

between USDWs when appropriate and where it can be demonstrated that USDWs will be protected;

and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to

addressing injection depth variability through a waiver process responds to concerns about future

drinking water resource availability and the need to ensure that high quality water remains available

in sufficient quantities to supply drinking water needs. For additional information on the waiver

approach, please see the final rule and preamble, as well as EPA's responses to comments on the

Notice of Data Availability and Request for Comment.

Commenter Name: Diane VanDe Hei Letter ID: 0213

Commenter Organization: Association of Metropolitan Water Agencies

(AMWA)

Comment ID:

22947

Comment: - 73 FR 43512 - EPA requests comment on whether CO2 injection should be allowed 

into an injection zone above the lowermost USDW, when the Director determines 

that geologic conditions exist that will prevent fluid movement into adjacent 

USDWs. 

Response: AMWA opposes the injection into any formation above the lowermost 
existing or potential USDW and recommends that EPA take a phased approach and 

prohibit the construction of CO2 sequestration wells in aquifers currently used 

for drinking water supply or expected to be used in the future, until more is 

known about the risks of CO2 sequestration to USDWs as a result of the effects 

and dynamics of the fluid in the subsurface. Congress intended the UIC program 

to protect sources and potential sources of drinking water from contamination: 

"Underground injection endangers drinking water sources if such injection may 

result in the presence in underground water which supplies or can reasonably be 

expected to supply any public water system of any contaminant, and if the 

presence of such contaminant may result in such system’s not complying with any 

national primary drinking water regulation or may otherwise adversely affect the 

health of persons." SDWA § 1421(d)(2); 42 U.S.C. § 300h(d)(2). 

AMWA believes that allowing the injection of CO2 above a USDW would endanger the 

USDW by providing a pathway for CO2 to contaminate a drinking water source, 

especially if a well was constructed through a CO2 plume. 

Response: EPA agrees that protecting USDWs from endangerment must be a top priority. The

Agency believes that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. It establishes: 1) requirements specifying information that owners or operators must

submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for public

notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class

VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. 

EPA believes that the requirements at §146.95 will ensure USDW protection while providing

flexibility to UIC Program Directors and owners or operators who undertake CO2 injection for GS.

The Agency believes this approach: 1) responds to concerns about local and regional geologic

storage capacity limitations imposed by the proposed injection depth requirements; 2) allows for a

more site-specific assessment of injection depth for GS projects; 3) accommodates injection into

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or

between USDWs when appropriate and where it can be demonstrated that USDWs will be protected;

and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to

addressing injection depth variability through a waiver process responds to concerns about future

drinking water resource availability and the need to ensure that high quality water remains available

in sufficient quantities to supply drinking water needs. For additional information on the waiver

approach, please see the final rule and preamble, as well as EPA's responses to comments on the

Notice of Data Availability and Request for Comment.

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost

USDW 
Individual Comments

Commenter Name: Karl R. Moor Letter ID: 0109

Commenter Organization: Southern Company, on behalf of Edison Electric

Institute (EEI)

Comment ID:

22008

Other EPA Comment Codes and Descriptions: 4410 2.4.4.3.1 Comments in favor of allowing

injection above/between USDWs in certain circumstances 

Comment: Similarly, the regulations should be sufficiently flexible to allow operators of 

geologic storage facilities, as well as operators of enhanced oil recovery or 

enhanced gas recovery projects converting their operations to geologic carbon 

storage facilities, to site these projects above underground sources of drinking 

water, if they can show there is unlikely to be harm to USDW. The proposed 

regulations make this nearly impossible since they would restrict injection for 

long-term storage to formations that are below the lowermost underground source 

of drinking water. Enhanced oil recovery and enhanced gas recovery facilities 

have been injecting carbon dioxide into formations above underground sources of 

drinking water for more than 30 years without migration or leakage incidents. 

Rather than reject these types of projects as potential geologic carbon storage 

sites by rule, EPA should permit the owners and operators of these kinds of 

projects to make their case based on the specific characteristics of each site. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach and

aquifer exemptions for Class VI wells, please see the final rule and preamble, as well as EPA's

responses to comments on the Notice of Data Availability and Request for Comment.

While the Agency acknowledges the experience gained by the oil and gas industry and other

injection activities, EPA identified unique challenges posed by large-scale GS including large

injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the

potential presence of impurities in captured CO2, and its mobility within subsurface geologic

formations that warrant the tailored approach in the GS rule. Furthermore, the Agency believes that

wells that inject into non-USDW formations above and between USDWs presents additional
challenges that warrant additional requirements.

Commenter Name: Brian Williams Letter ID: 0116

Commenter Organization: BP Alternative Energy Comment ID: 22053

Comment: No CO2 injection above lowest known USDW -- BP does not subscribe to a blanket, 

artificial constraint that would limit injection only to reservoirs below the 

USDW. More appropriate, given the EPA’s general performance-based approach, 

would be to place containment requirements on the acceptable reservoirs. As long 

as CO2 can be injected and stored securely, with minimal chance for breaching 

containment (either via wellbore or geological features), proximity to USDWs, 

whether shallower or deeper, should not matter. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

Additionally, the final GS rule does not categorically preclude or prohibit injection into any type of

formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach and

aquifer exemptions for Class VI wells, please see the final rule and preamble, as well as EPA's

responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24755

Comment: §144.6 Classification of wells. 

{The proposal includes in the definition of "Class VI" the restriction that 

injection into such wells must be "beneath the lowermost formation containing a 

USDW." RRC suggests either removing the restriction or adding "or another 

formation, if the Director determines that injection into the other formation 

will be protective of USDWs." } 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which
owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

Additionally, the final GS rule does not categorically preclude or prohibit injection into any type of

formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach and

aquifer exemptions for Class VI wells, please see the final rule and preamble, as well as EPA's

responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24757

Comment: Part 146 UIC Program Criteria and Standards 

§146.5 Classification of injection wells. (f) Class VI. 

{The proposal includes in the definition of "Class VI" the restriction that 

injection into such wells must be "beneath the lowermost formation containing a 

USDW."} 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs. The final rule

also establishes limited circumstances under which expansions of the areal extent of aquifer

exemptions may be granted for owners or operators of Class II EOR/EGR wells transitioning to

Class VI injection for GS. Additionally, the final GS rule does not categorically preclude or prohibit

injection into any type of formation.

For additional information on the waiver approach and aquifer exemptions for Class VI wells, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Ronald Surdam Letter ID: 0132

Commenter Organization: Wyoming State Geological Survey Comment ID: 21542

Comment: The requirements of injecting CO2 only below the lowermost Underground Source of 
Drinking Water (USDW) aquifer will make it impossible to inject CO2 into deep 

saline aquifers in Rock Mountain Laramide Basins (RMLB). The problem is when 

the deep geological sequestration CO2 targets in RMLB (i.e., deep saline 

aquifers) occur near the surface, they contain USDW. For example, at a depth of 

10,000 to 15,000 feet, a stratigraphic unit such as, but not limited to the 

Madison Limestone, typically has salinity > 10,000 ppm. However, this same unit 

at 0-3,000 feet depth typically has salinity < 500 ppm. Near the surface, the 

aquifer is recharged with copious quantities of fresh meteoric water; but, 

because of geohydrologic characteristics common to Laramide Basins of Wyoming, 

the fresh water does not circulate into the deeper portions of the basin. 

Instead, it discharges in the form of springs or into streams/rivers near the 

margin of the basin typically along bounding faults or breached, anticlinal 

structures. As a consequence, due to a lack of mixing meteoric and connate 

fluids, the fluid in the same unit at a depth of 10,000 feet maintains 

salinities more near the original depositional environment (i.e., marine waters 

with salinities > 30,000 ppm). If the formation fluid was part of a continuous 

fluid-flow system, the whole rock/fluid system would have been flushed during 

the Pleistocene when recharge rates were much higher than today. Observations 

made in all of Wyoming’s Laramide Basins demonstrate that fluid-flow systems in 

the deep saline aquifers are compartmentalized resulting in an absence of 

shallow-formation water mixing with deep basin brines. 

The ramifications of declaring a stratigraphic unit in Rocky Mountain Basins a 

USDW aquifer because it supplies fresh water at shallow depth are immense. The 

stratigraphic section beneath units such as the Paleozoic Madison Limestone and 

the Tensleep Sandstone (or stratigraphic equivalent units) is relatively thin in 

Wyoming. If the intention is to use geological CO2 sequestration as an 

effective mitigation tool for global climate change, the stratigraphic section 

between the Tensleep/Madison does not have the storage volume required to 

accommodate the huge quantities of CO2 that will need to be geologically 

sequestered. 

The Wyoming State Geological Survey suggests that our Nation will be much better 

served if the proposed regulations for geological CO2 sequestration, with 

respect to injecting CO2 only below the lowest USDW aquifer, be modified as 

follows: “Geological CO2 sequestration will be allowed in deep saline aquifers 

in Rocky Mountain Laramide Basins unless it can be demonstrated that the 

injected CO2 will have a deleterious effect on USDW.” 

If this change is not made, the geological sequestration of CO2 will be far more 

onerous than injecting H2S into the deep portion of RMLB. For economic and 

regulatory purposes, the regulations as proposed will make geological 

sequestration of CO2 impossible. To promulgate a geological CO2 sequestration 

regulation for RMLB out of the context of Rocky Mountain Laramide geology will 

make it extremely difficult to mitigate the effects of greenhouse emissions on 

climate change in the West. The Wyoming State Geological Survey requests that 

the United States Environmental Protection Agency act favorably on the changes 

herein described. 

Response: EPA acknowledges that there are limited circumstances where injection above the
lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying

information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements

to ensure USDW protection above and below the injection zone. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Dawn A. Thorne Letter ID:

0134

Commenter Organization: University of Utah Energy and Geoscience Institute on

behalf of the Southwest Regional Partnership

Comment

ID: 21657

Comment: - Section 146.86(b)(2) "Surface casing must extend through the base of the 

lowermost USDW and be cemented to the surface." 

Response/Discussion: It is the opinion of the SWP that this section may 

unnecessarily eliminate viable target reservoirs from GS. The SWP recommends a 

site-specific risk-based approach for determining siting criteria. As discussed 

in the first point of this letter, detailed siting criteria with respect to 

injection and confining zones are evaluated in Section 146.83(b) of the proposed 

rule. A definitive rule eliminating injection into any zone above a USDW without 

scientific justification appears to be preliminary in nature and again, may 

create the perception of fear among the public. The SWP recommends either 

removing this section from the final rule or, if kept in the rule, then it be 

expanded to include a site-specific, risk-based approach for approval of 

drilling, casing, and other relevant variances into an injection zone above a 

USDW. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The waiver approach requires the
submission of extensive, site-specific information (in conjunction with the permit application

submission) to demonstrate that injection of CO2 into a non-USDW that is above or between

USDWs can be done in a manner that is protective of USDWs. The requirements are designed to

ensure that the owner or operator, the Director, and the Regional Administrator consider, on a site

specific basis, the implications, benefits, and challenges associated with GS and ensuring water

availability and USDW protection. EPA believes that the additional procedures for public notice of a

waiver application and for Director-Regional Administrator communication at §146.95 will improve

public confidence in and acceptance of GS projects operating under injection depth waivers. 

EPA clarifies that, due to the unique nature of the injection depth waiver process and in an effort to

ensure national consistency and application of the requirements, the requirement at §146.95(d)

indicates that the Regional Administrator makes the final determination regarding waiver issuance

following an evaluation of all site-specific information, public notice, and recommendations from

the UIC Director. 

EPA agrees that a site-specific approach is appropriate. The waiver approach requires the submission

of extensive, site-specific information (in conjunction with the permit application submission) to

demonstrate that injection of CO2 into a non-USDW that is above or between USDWs can be done

in a manner that is protective of USDWs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141

Commenter Organization: Global Energy, Inc. Comment ID: 23122

Comment: Proximity to USDW 

1.State discretion to decide whether injection below the lower most USDW is 

necessary. It is reasonable that certain combinations of geologic strata can 

readily protect a USDW from above not just from below. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Determinations regarding the

appropriateness of an injection depth waiver would be made by the Director, based on site-specific

information. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.
Commenter Name: Patrick Nugent Letter ID: 0143

Commenter Organization: Texas Pipeline Association (TPA) Comment ID: 23142

Comment: 10. Requiring that the injection zone be below the lowermost USDW is onerous 

and unjustified. TPA disagrees with the proposal that geologic sequestration be 

limited in all cases to an injection zone that occurs below the lowermost 

underground source of drinking water ("USDW"). Rather, a performance-based 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs.

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Dave Freudenthal Letter ID: 0150

Commenter Organization: State of Wyoming Comment ID: 22219

Other EPA Comment Codes and Descriptions: 2123 1.6.1.1 Comments in favor of injection into

deep saline 

Comment: Unfortunately, the overarching framework and specific rule provisions pertaining 

to suitable re-injection locations contemplated in Docket ID No. EPA-HQOW-2008-0390 prematurely exclude consideration of geologic structures with deep 

saline aquifers that occur in Wyoming. By eliminating the use of these deep 

saline aquifers, the rules would effectively preclude Wyoming from participating 

in CO2 sequestration efforts and effectively disregards the technical expertise, 

referenced earlier, that exists in Wyoming. This broad brush, generalized 

approach deprives Wyoming and the rest of the region from viable consideration 

for CO2 sequestration opportunities. 

I ask that you carefully review the comments submitted by the Wyoming State 

Geological Survey (WSGS) which explain why our nation will be much better served 

if the proposed regulations for geological CO2 sequestration are modified. With 

respect to the depth of injection of C02, the proposed rules only allow 

injection at levels below the lowest underground source of drinking water (USDW) 

aquifer. As WSGS explains, the language needs to be modified to read: 
"Geological CO2 sequestration will be allowed in deep saline aquifers in Rocky 

Mountain Laramide Basins (RMLB) unless it can be demonstrated that the injected 

CO2 will have a deleterious effect on USDW." 

This change will allow for the use of geologic formations with deep saline 

aquifers, which we believe can be safely used for the injection of CO2 in 

Wyoming and other western states. If this change is not made, an illogical 

result will occur in which the proposed sequestration rules for CO2 will be more 

onerous than the rules for injecting hydrogen sulfide into deep saline aquifers. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS.

Commenter Name: Brianne Metzger Letter ID: 0151

Commenter Organization: Spectra Energy Corp Comment ID: 21822

Comment: D. EPA Should Not Arbitrarily Preclude Injection Into Certain Formations Located 

Above The Lowermost USDW. 

Under the Proposed Rule, EPA has proposed limiting the injection of CO2 to 

below the lowermost USDW. Spectra believes that it is premature for the 

Agency to preclude the injection of CO2 into formations such as unmineable coal 

seams, depleted oil and gas reservoirs, zones in between or above USDWs, or 

other formations. As EPA points out, imposing such a limit may preclude the 

application of GS in areas such as the Williston and Powder River Basins in 

Wyoming and North and South Dakota, where the lowermost USDW is located 

thousands of feet below the surface. In these cases, we agree with EPA that GS 

may still be appropriate and, therefore, the Director should have the 

discretion to make such determinations. Such determination must ultimately be 

made based on the protection of USDWs. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to
concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Steven Pirner Letter ID: 0153

Commenter Organization: South Dakota Department of Environment and

Natural Resources

Comment ID:

22136

Comment: location of formations where CO2 can be sequestered. At this point EPA is 

proposing to only allow sequestration in formations below the lowermost USDW (as 

noted in 144.6 (f), and 146.5 (f)). In South Dakota there are strata that could 

potentially be used for sequestration that are above the lowermost USDW and have 

significant confining beds. The eastern portion of the state is generally 

unsuitable for sequestration as the Precambrian basement rock is less than 3000 

feet deep in most places, is used as a USDW in some areas, and an additional 

USDW directly overlies it in some cases. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Jeff Moseley Letter ID: 0155

Commenter Organization: Greater Houston Partnership (GHP) Comment ID: 21261

Comment: 8 . Revise the proposed requirement that CO2 storage must occur below the 

deepest USDW; this is unnecessarily stringent. The rules should allow site 

selection based upon more flexible, site-specific considerations. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which
owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: James Childress Letter ID: 0158

Commenter Organization: Gasification Technologies Council (GTC) Comment ID: 23760

Comment: Concern #5: Restriction of injection to formations below the lowermost 

underground source of drinking water or USDW. (Ref page 43512, 3. Proposed 

Injection Well Construction Requirements) 

This requirement is not necessary for the protection of USDWs. It is in-fact 

overly restrictive and will eliminate many suitable and safe geologic formations 

for CO2 sequestration or permanent storage. It will also render geological 

storage impractical (pumping power and well costs) for states in the western 

United States where the drinking water aquifers are many thousands of feet deep 

and well isolated from overlying regions. Also, industry has demonstrated that 

it can operate CO2 injection wells for EOR without endangering USDWs that are 

located below the injection zone (e.g., the Salt Creek EOR project in Wyoming, 

having a USDW below the injection zone). 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying

information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements

to ensure USDW protection above and below the injection zone.

While the Agency acknowledges the experience gained by the oil and gas industry and other

injection activities, EPA identified unique challenges posed by large-scale GS including large

injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the

potential presence of impurities in captured CO2, and its mobility within subsurface geologic

formations that warrant the tailored approach in the GS rule. Furthermore, the Agency believes that
wells that inject into non-USDW formations above and between USDWs presents additional

challenges that warrant additional requirements. 

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Sandi Tabor Letter ID: 0162

Commenter Organization: Lignite Energy Council (LEC) Comment ID: 21301

Comment: In the final analysis, the state UIC directors should have the discretion to 

allow injection into coal seams, oil and gas formations, and other formations 

located above the lowermost USDW, where site-specific characteristics indicate 

that those formations are good candidates. Proper site characterization and 

engineering are more important in determining a suitable site than a blanket 

prohibition. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final GS rule does not categorically

preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. For additional

information on the waiver approach and aquifer exemptions for Class VI wells, please see the final

rule and preamble, as well as EPA's responses to comments on the Notice of Data Availability and

Request for Comment.

Commenter Name: James Stine Letter ID: 0163

Commenter Organization: National Rural Electric Cooperative Association

(NRECA)

Comment ID:

21322

Other EPA Comment Codes and Descriptions: 4410 2.4.4.3.1 Comments in favor of allowing

injection above/between USDWs in certain circumstances 

Comment: NRECA supports alternative approaches that would allow injection between and/or 

above the lowermost USDW, increasing capacity for CO2 GS, as long as Owners or 

Operators of Class VI wells can show that their CO2 GS operations will be 

protective of USDWs. Id. at 43512. This will be particularly important in areas 

of the country with deep USDWs, where an absolute requirement that Class VI 

wells be constructed beneath the lowermost USDW could render the program 

impractical. Id. NRECA also supports this alternative approach in areas where 

the Director determines -- or the Owner or Operator can show -- that geologic 

conditions would prevent fluid movement into adjacent USDWs. Id. For similar 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying
information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements

to ensure USDW protection above and below the injection zone. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Michael Mudd Letter ID: 0167

Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 22459

Comment: Stratigraphic Restriction of Saline and Other Reservoirs to Below Lowermost USDW 

The Proposed Regulation for saline formations state: 

p. 43494, c. 2 Saline formations: Deep and geographically extensive sedimentary 

rock layers saturated with waters or brines that have a high total dissolved 

solids (TDS) content (i.e., >10,000 mg/L TDS). 

Proposed Geologic Siting Requirements: p.43505, c. 1 Existing UIC requirements 

for siting injection wells include identification of geologic formations 

suitable to receive the injected fluids and confine them such that they are 

isolated below the lowermost USDWs, minimizing the potential for endangerment. 

Target geologic formations: p.43502-43503, section H As with unmineable coal 

seams, EPA seeks comment on prohibiting injection into such formations [basalts, 

salt domes, and shales] if they are above the lowermost USDW. 

The EPA is soliciting comments on these issues: 

1.Whether CO2 injection should be allowed into an injection zone (saline 

sedimentary formations, unminable coal seam, basalt, salt caverns, shales, or 

other reservoirs) above the lowermost USDW, when the Director determines that 

geologic conditions exist that will prevent fluid movement into adjacent USDWs. 

2.Whether a designated USDW should be exempted to allow for GS, and under what 

conditions should these exemptions be approved. 
3.Whether all USDWs should be exempted below a CO2 injection receiving bed. 

4.Whether the EPA should set a minimum injection depth requirement for GS, 

rather than require that such injection take place below the lowermost USDW. 

Comments: 

GS should be permitted in the following: 

1)reservoirs containing >10,000 mg/L TDS, 

2) where the formation water is <10,000 mg/L but is non-potable for other 

reasons, or 

3)formations exempted as USDWs by the state. 

GS should not be restricted to stratigraphic zones below the lowermost USDW. 

- Prohibition of CO2 injection into saline formations above USDWs is overly 

restrictive and would severely limit GS in states such as Wyoming, where deep 

sedimentary formations in much of the state have TDS lower than 10,000mg/l 

(NETL). Thus almost any formation considered for GS would likely overlie a low 

TDS formation. 

- GS should be allowed into an injection zone above the lowermost USDW (whether 

saline or other formation) when the Director determines that geologic conditions 

exist that will prevent fluid movement into nearby USDWs. Conditions that will 

prevent downward movement of fluids include the presence of intact low 

permeability beds between the receiving bed and the underlying USDW. In 

consideration of the buoyant behavior of injected CO2, the requirement of 

thousands of feet of intervening formations may be less important than the 

demonstration of the sealing capacity of the intervening layers. We believe that 

"thousands of feet" is a vague requirement, when the more rigorous test is the 

demonstration of the sealing capacity of the intervening layers. 

- The draft rule is far too restrictive and is not based on technical risk 

factors. Risk of CO2 contamination to a USDW is lower for aquifers that 

underlie an injection reservoir due to the inherent buoyancy of the CO2. 

Vertical migration can be interrupted completely by the presence of one or more 

low permeability layers. Hence, a prohibition on injecting above the shallowest 

USDW is not based on real technical risk of a GS project. 

- The conditions for exemptions of aquifers should be clarified. Aquifer 

exemptions should be allowed for GS ("a receiving bed for Class VI wells") when 

it can be demonstrated that there is no reasonable expectation that the 

formation will be considered for a drinking water source, and when it can be 

demonstrated that CO2 is highly unlikely to migrate updip into a portion of the 

formation that may be considered for use as a USDW. 

- Blanket aquifer exemption of all USDWs below a GS zone is not needed if there 
is demon-stration of a competent seal between the injection zone and the first 

underlying USDW. 

- No blanket prohibition should be introduced for any potential non-saline 

reservoir; promising GS targets of basalt, unmineable coal seams, etc., should 

be evaluated with methodologies similar to those for saline formations. 

- GS is better served by neither mandating a set minimum depth for injection nor 

by requiring injection take place below the lowermost USDW. Minimum depth 

requirements would be unnecessarily proscriptive. Shallow injections could be 

done for very small commercial producers or in cases where reservoir engineering 

practices (such as pre-dissolution of the CO2 into formation water) are done so 

that no free CO2 phase exists. 

Three of the most important issues here are (a) the physical location of saline 

formations or other types of geologic reservoirs for GS, relative to USDWs; (b) 

under what circumstances the EPA should remove one or more water-bearing zones 

from the list of USDWs to allow injection; and (c) under what other conditions 

should the EPA allow injection above a USDW. 

In addition to injection into saline formations, EPA recognizes that basalt, 

unmineable coal seams, salt domes, abandoned mines, black shales and other types 

of reservoirs may be promising, emerging targets. Basalts, in particular appear 

to have considerable potential for GS. Research by PNNL and others indicates 

that extruded basalt flow tops and flow bases may have regional, multi-gigaton 

capacity for CO2 storage. In addition, laboratory experiments suggest that 

mineralization of large volumes of CO2 may proceed within a few years of 

injection (McGrail et al, 2006). 

In the proposed rule, the new Class VI wells would be allowed to inject CO2 into 

basalts, deep saline reservoirs, and other potential reservoirs only when they 

are beneath the lowermost USDW. 

A USDW is defined by the EPA as "An aquifer or portion of an aquifer that 

supplies any public water system or that contains a sufficient quantity of 

ground water to supply a public water sys-tem, and currently supplies drinking 

water for human consumption, or that contains fewer than 10,000 mg/l total 

dissolved solids and is not an exempted aquifer." This definition would include 

many non-potable aquifers that would be candidates for GS. 

The EPA’s reliance on the standard definition of a USDW as being solely <10,000 

mg/L TDS is far too restrictive. In many states, this standard is not applied - 

all groundwaters are protected regardless of water quality. In at least one 

state GS operations would be permitted if removing anthropogenic CO2 is 

considered a greater public benefit than the loss of a marginal aquifer. 

The EPA is aware that restricting GS to a position below all EPA defined USDWs 

would severely limit GS in many areas. Under the current proposed rule, 

directors may grant injection into deep, marginal USDWs that directly overlie 

crystalline basement rock and/or unmineable coal seams. In addition to these 
exceptions, the EPA would consider allowing operation of GS wells where 

receiving formations are above the lowermost USDW only where there are thousands 

of feet between the injection zone and the overlying and underlying USDWs. 

As currently defined by the EPA, "aquifer exemptions" permanently remove a 

specified aquifer from protection as a USDW. Aquifer exemptions are currently 

granted for mineral or hydrocarbon exploration by Class III solution mining 

wells, or by Class II oil and gas related wells, when there is no reasonable 

expectation that the formation will be used as a drinking water supply. It is 

important to note that the EPA has not previously considered the purpose of 

creating additional capacity for the emplacement of fluids as sufficient cause 

for granting an exemption. Under the new rule, it would be possible for 

operators to apply to change the designation of some aquifers being used for 

Class II injection. These aquifers would need a new, separate exemption for GS. 

The EPA suggests the following possible alternatives that would allow injection 

between USDWs or above the lowest USDW: 

1.Injection approval for GS between USDWs formations is at the Director’s 

discretion in circumstances in which it may be demonstrated that USDWs would not 

be endangered. 

2.Directors may be allowed to exempt, at their discretion, all USDWs below a GS 

injection zone. (This would permanently remove these aquifers from protection as 

USDWs). 

References McGrail, B. P., H. T. Schaef, A. M. Ho, Y. Chien, J. J. Dooley, and 

C. L. Davidson. 2006. Potential for Carbon Dioxide Sequestration in Flood 

Basalts, J. Geophys. Res. 111, B12201. 

NETL. 2007. National Carbon Sequestration Atlas. 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlas/index.html 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS. The final

rule allows for the expansion of the areal extent of existing aquifer exemptions for Class II

EOR/EGR wells transitioning to Class VI injection for GS pursuant to requirements at §§146.4 and

144.7(d). Class VI owners or operators granted expansions of existing Class II EOR/EGR aquifer

exemptions for GS projects must meet all of the tailored requirements for Class VI wells in the final

GS rule. Additionally, the final GS rule does not categorically preclude or prohibit injection into any

type of formation. 

EPA agrees that it is not appropriate to set a minimum injection depth for GS projects and the

Agency believes that a determination of site-suitability for GS (i.e., that subsurface formations will

receive and confine injected CO2) should be made on a site-specific basis. The GS rule, at §146.82,
requires the owner or operator to provide extensive site- and project-specific information to the

Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be

contained within the injection formation, and that USDWs will be protected from endangerment.

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. 

For additional information on the waiver approach and aquifer exemptions for Class VI wells, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Michael J. Miller Letter ID: 0168

Commenter Organization: Electric Power Research Institute (EPRI) Comment ID: 22505

Comment: Preamble, page 43512: "In summary, EPA is soliciting comment on whether CO2 

injection should be allowed into an injection zone above the lowermost USDW, 

when the Director determines that geologic conditions (e.g., thousands of feet 

of intervening formations between the injection zone and the overlying and/or 

underlying USDWs) exist that will prevent fluid movement into adjacent USDWs. 

EPA is also requesting comments on whether aquifer exemptions should be allowed 

for the purpose of Class VI injection, and under what conditions should such 

aquifer exemptions be approved. Finally, EPA seeks comment on whether the Agency 

should set a minimum injection depth requirement for CO2 GS, rather than require 

that such injection take place below the lowermost USDW." 

EPRI COMMENT #11: EPRI believes that a proposed GS site should be considered to 

be protective of USDWs as long as the applicant demonstrates to the EPA that it 

meets the minimum siting criteria specified in §146.83(a)(1), (a)(2) (also see 

EPRI Comment #4). Whether or not the injection zone lies above or below the 

lower most USDW, or below a given depth, is not important as long as the minimum 

criteria are met. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying

information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements
to ensure USDW protection above and below the injection zone. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24121

Comment: Lowermost USDW Restriction 

EPA's proposal to restrict injection to formations below the lowermost USDW is 

not necessary for the protection of USDWs and would remove a significant number 

of viable formations from consideration as GS sites. Industry has shown that it 

can operate CO2 injection wells in an EOR context without endangering USDWs that 

are located below the injection zone. An excellent example is the Salt Creek EOR 

project in Wyoming, which has a USDW below the injection zone. Moreover, under 

the proposed rule, there are other measures that would provide real assurance of 

formation integrity and require operators to demonstrate that their project will 

not endanger USDWs, making the lowermost USDW restriction unnecessary. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high-quality water remains available in sufficient

quantities to supply drinking water needs. 
For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24135

Comment: Rationale: Additionally, there should not be a blanket prohibition concerning 

injection above USDW’s or at specific depths. This is especially true given the 

possibility of changes in the definition of a USDW to include formations greater 

than 10,000 parts per million Total Dissolved Solids. This requirement is not 

necessary for the protection of USDWs and would remove a vast number of viable 

formations from consideration. Industry has shown that it can operate CO2 

injection wells in an EOR context without endangering USDWs that are located 

below the injection zone. An excellent example is the Salt Creek EOR project in 

Wyoming, which has a USDW below the injection zone. Moreover, under the proposed 

rule, there are other measures that would provide real assurance of formation 

integrity and require operators to demonstrate that their project will not 

endanger USDWs, making the lowermost USDW restriction unnecessary. 

Response: As described above, EPA agrees that it is not appropriate to set a minimum injection

depth for GS projects and the Agency believes that a determination of site-suitability for GS (i.e.,

that subsurface formations will receive and confine injected CO2) should be made on a site-specific

basis. The GS rule, at §146.82, requires the owner or operator to provide extensive site- and projectspecific information to the Director to demonstrate that the site meets the minimum site criteria at

§146.83, that the CO2 will be contained within the injection formation, and that USDWs will be

protected from endangerment.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24137

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 2046

1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ dividing line between Class

II and Class VI (seeking comment) 

Comment: Rule Provision: 144.80 

API Comments: b) Class II. Wells which inject fluids:...... (4) FOR ENHANCED 

RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC SEQUESTRATION IS

OCCURRING DURING 

OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR NATURAL GAS

PROVIDED (I) THERE 

IS REASONABLE EXPECTATION OF MORE THAN INSIGNIFICANT FUTURE

PRODUCTION VOLUMES 

OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION AND (II) OPERATING

PRESSURES 

ARE NO HIGHER THAN REASONABLY NECESSARY TO PRODUCE SUCH VOLUMES OR

RATES; AND 

(5) FOR GEOLOGIC SEQUESTRATION IN OIL AND GAS FORMATIONS AND WHERE THE

CRITERIA 

OF PARAGRAPH (B)(4) ARE NOT MET 
(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon 

dioxide STREAMS. WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2 STREAMS

OCCURS DURING 

OR IN CONNECTION WITH EOR OR EGR ARE REGULATED UNDER CLASS II. 

Rationale: See 144.6 

Response: As described above regarding the suggested edit at 144.6, EPA did not make the

suggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of longterm storage should be regulated under Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24138

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 2046

1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ dividing line between Class

II and Class VI (seeking comment) 

Comment: Rule Provision: 146.5 

API Comments: b) Class II. Wells which inject fluids:...... (4) FOR ENHANCED 

RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC SEQUESTRATION IS

OCCURRING DURING 

OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR NATURAL GAS

PROVIDED (I) THERE 

IS REASONABLE EXPECTATION OF MORE THAN INSIGNIFICANT FUTURE

PRODUCTION VOLUMES 

OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION AND (II) OPERATING

PRESSURES 

ARE NO HIGHER THAN REASONABLY NECESSARY TO PRODUCE SUCH VOLUMES OR

RATES; AND 

(5) FOR GEOLOGIC SEQUESTRATION IN OIL AND GAS FORMATIONS AND WHERE THE

CRITERIA 

OF PARAGRAPH (B)(4) ARE NOT MET 

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon 

dioxide STREAMS. Beneath the lowermost formation containing an underground 

source of drinking water (USDW). WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2 

STREAMS OCCURS DURING OR IN CONNECTION WITH EOR OR EGR ARE REGULATED

UNDER CLASS 

II. 

Rationale: See 144.6 

Response: As described above regarding the suggested edit at 144.6, EPA did not make the
suggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of longterm storage should be regulated under Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

EPA clarifies that the final rule requires that injection for GS be into non-USDWs below the

lowermost USDW; however, owners or operators may apply for a waiver from this requirement, as

described in §146.95. For more information, see the discussion of waivers in the preamble to the

final rule.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs from endangerment, as long as appropriate

protections are in place. However, EPA disagrees with the suggested addition to the regulation. The

final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver of the

Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. It establishes: 1) requirements specifying information that owners or operators

must submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for

public notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class

VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. 

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24145

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: Rule Provision: 146.81(d) [Definition - Geologic sequestration project] 

API Comments: Geologic sequestration project means an injection well or wells 

used to emplace a carbon dioxide stream beneath the lowermost formation 

containing a USDW INTO AN INJECTION ZONE EXCLUSIVELY FOR THE PURPOSE OF 

GEOLOGIC SEQUESTRATION. It includes the subsurface three-dimensional extent of 

the carbon dioxide plume, associated pressure front, and displaced brine, as 

well as the surface area above that delineated region. 

Rationale: There should not be a blanket prohibition concerning injection above 

USDW’s or at specific depths. This requirement is not necessary for the 

protection of USDWs and would remove a vast number of viable formations from 

consideration. Industry has shown that it can operate CO2 injection wells in an 

EOR context without endangering USDWs that are located below the injection zone. 

An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

measures that would provide real assurance of formation integrity and require 

operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long
as appropriate protections are in place. However, EPA disagrees with the suggested change. For

additional information, please see the final rule at §146.95 and the preamble, as well as EPA's

responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: James Rower Letter ID: 0173

Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23494

Comment: Additional injection sites - As discussed above, it is likely that there will be 

great demand for wells in which to inject CO2 for GS, with the potential need 

for tens of thousands of additional sites. Accordingly, the goal of the Program 

should be to provide as much capacity as possible for CO2 GS while still 

ensuring that USDWs are not jeopardized. USWAG supports alternative approaches 

that would allow injection between and/or above the lowermost USDW, increasing 

capacity for CO2 GS, as long as Owners or Operators of Class VI wells can show 

that their CO2 GS operations will be protective of USDWs. Id. at 43512. This 

will be particularly important in areas of the country with deep USDWs, where an 

absolute requirement that Class VI wells be constructed beneath the lowermost 

USDW could render the program impractical. Id. USWAG also supports this 

alternative approach in areas where the Owner or Operator can show that geologic 

conditions would prevent fluid movement into adjacent USDWs. Id. For similar 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Pamela Faggert Letter ID: 0175

Commenter Organization: Dominion Comment ID: 23519

Comment: a. Limitations on Receiving Formations above the lowermost USDW 

The proposal contemplates injection only below the lowermost USDW. Such a 

prohibition is troublesome for several reasons. First, it is unnecessary for the 

protection of USDW. There are numerous other safeguards affording necessary 

protections of USDW when demonstrated appropriately in the permitting process 
(e.g. injection zone characteristics, geology, modeling, confining zone, depth, 

fluid composition, etc). Secondly, such a categorical exclusion may 

unnecessarily eliminate vast storage formations that may be the only 

geographically feasible GS site for some sources of CO2 (e.g. unmineable coal 

seams, experimental formations, etc). Third, it is likely to hamper commercial 

development of CCS, as EOR wells are likely the early adopters of GS wells and 

some EOR wells would be excluded from transitioning to Class VI wells with such 

a prohibition. Lastly, it is likely to create unfavorable public perception 

issues if GS is treated so categorically similarly to Class I Hazardous Waste 

wells. 

There should be no blanket prohibition against injection into any 

approved geologic zone even if above the lowermost USDW. There are 

circumstances where this may be perfectly appropriate and safe. The 

decision needs to be site specific and based on evaluation of local 

geology and other factors. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

EPA agrees that proper siting, monitoring, and containment capacity are critical elements of Class VI

injection for GS. However, the Agency also believes that injection into non-USDW formations above

and between USDWs presents unique challenges related to movement of CO2 in the subsurface,

which requires a unique approach to ensure that USDWs are protected. Therefore, the Agency

believes that additional requirements are appropriate and necessary for wells that would inject into

non-USDWs above and between USDWs.

Commenter Name: Kenneth Nemeth Letter ID: 0176

Commenter Organization: Southern States Energy Board Comment ID: 23539

Comment: could be used for GS nor any depth limitations on injection zones. SSEB does not 

support limiting a GS project beneath a sole source USDW aquifer or above the 

lowermost USDW. These restrictions would only serve to limit a GS project from 
being sited in what would otherwise be very safe geology. SSEB also does not 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Quinlan J. Shea Letter ID: 0177

Commenter Organization: Edison Electric Institute Comment ID: 23578

Other EPA Comment Codes and Descriptions: 2100 1.6 Target Geologic Formations for GS 

Comment: The first such requirement relates to the Agency‘s proposed limitations on 

receiving formations. The proposed regulations would permit project operators 

to inject and store CO2 only beneath the lowermost formation containing USDW. 

Such a categorical limitation on receiving formations is unnecessary, unduly 

burdensome and undesirable for several reasons: 

- Unnecessary for protection of USDW under the UIC program: As a preliminary 

matter, categorically eliminating a body of potential receiving formations is 

simply unnecessary in light of the overall function of the UIC rules. As a 

general proposition, UIC permit applicants must demonstrate that projects will 

not endanger USDW; permit applicants for CO2 injection and storage projects 

would be held to the same standard.[FN4] The proposed rules would also require 

permit applicants to demonstrate that the project will be sited in areas with a 

"suitable geologic system"--consisting of an injection zone of sufficient areal 

extent, thickness, porosity and permeability to receive the total anticipated 

volume of injectate--and a confining zone free of transmissible faults or 

fractures and sufficient to contain the injected stream as well as any displaced 

fluids, considering the proposed maximum pressures and volumes of injection, 

without causing fracturing. Thus, the suitability of the receiving formation 

and the project‘s general protectiveness of USDW will necessarily be evaluated 

as a part of each GS permitting exercise. 

- All projects (and receiving formations) are not created equal: Each potential 
project will possess its own unique characteristics, as will each potential 

project site and receiving formation. A blanket requirement excluding a class 

of potential receiving formations imposed outside the context of actual projects 

is unnecessary, as for any given receiving formation or any given project, there 

may exist other characteristics that serve to provide equivalent or greater 

protection for USDW. 

- Likely to create public perception issues: Currently, a limitation on 

injections to only those formations below the lowermost USDW is in place solely 

for Class I hazardous waste injection wells. The properties of CO2, while 

unique in some respects, do not require or warrant such heightened treatment. 

Imposing a requirement currently in place only for hazardous waste would be 

likely to create the misperception that CO2 injection wells are analogous to 

hazardous waste injection wells and thus carry analogous risks. Accurate public 

perceptions about the nature of CO2 and the true risks associated with properly 

sited and executed storage projects are crucial to the success of CCS. 

- Likely to hamper commercial deployment of CCS, particularly for enhanced oil 

recovery (EOR) first actors: Much of the experience and expertise associated 

with injection and storage of CO2 that currently exists is the result of several 

decades of experience with EOR and enhanced gas recovery (EGR) operations 

through Class II UIC permits. As CCS gains momentum as a GHG mitigation tool, 

EOR operators may provide not only this wealth of experience and expertise, but 

also the first push toward commercial CCS by seeking to convert existing EOR 

operations to purely storage operations to take advantage of whatever credits 

may eventually become available under climate change legislation or 

regulation.[FN5] Some of those operations inject CO2 into formations that are 

above the lowermost USDW. Under the regulations currently proposed, however, 

existing Class II wells--as well existing CCS pilot projects permitted as either 

Class I or V wells--would be eligible only for the most limited scope of 

"grandfathering": the proposed grandfathering provision, discussed further 

below, would cover only construction requirements and not the remaining 

provisions of the Class VI regulations, including in particular the proposed 

limitation on receiving formations. Thus, existing projects that do not inject 

beneath the lowermost USDW could be left with no ability to convert to Class VI 

GS projects, disincentivizing many potential first actors. Moreover, creation 

of such a disincentive is unnecessary, as the wells at issue would have been 

designed and constructed specifically with injection of CO2 and the protection 

of USDW in mind. 

[FN4] EEI notes that EPA has proposed prohibiting CO2 storage in unmineable 

coal seams, basalts, salt domes and shales because "these formations are limited 

in geographic and geologic distribution in the U.S., and their technological or 

economic viability as GS sites has not been demonstrated." 73 Fed. Reg. 43503, 

col. 2. EEI urges EPA to continue to permit GS projects in these formations as 

Class V experimental wells to facilitate continued research into the potential 

for these formations to safely and economically store CO2, particularly because 

there are some areas of the country without easy access to saline formations or 

depleted oil and gas reservoirs that can be used for GS projects. 
[FN5] Of course, nothing in the proposed rule would prevent any owner or operator 

of a CO2 storage project, regardless of permit class, from seeking credits 

related to its participation in any future cap-and-trade program. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

Additionally, the final GS rule does not categorically preclude or prohibit injection into any type of

formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

While the Agency acknowledges the experience gained by the oil and gas industry and other

injection activities, EPA identified unique challenges posed by large-scale GS including large

injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the

potential presence of impurities in captured CO2, and its mobility within subsurface geologic

formations that warrant the tailored approach in the GS rule. Furthermore, the Agency believes that

wells that inject into non-USDW formations above and between USDWs presents additional

challenges that warrant additional requirements. 

Regarding the suggestion to allow experimental GS wells to continue to operate under Class V, EPA

anticipates that some owners or operators will apply for Class V experimental technology permits for

injection into formations including shallow basalts, coal seams, salt caverns and shales. These

formations may or may not be located above the lowermost USDW or between USDWs. To

facilitate experimental injection for GS and to increase understanding of injection into these

formation types, the Agency is amending the Class V experimental technology guidance. The

guidance will be available on EPA's web site, at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. EPA acknowledges that the Class

V experimental technology well sub-classification may be appropriate for these projects, provided

they are experimental in nature. EPA expects that, following the final GS rule, a limited number of

experimental injection projects testing GS technology will continue. EPA anticipates that these

projects will be small-scale and involve limited CO2 volumes. However, if these projects become

larger scale and are no longer experimental, they will need to be permitted as Class VI wells. The

construction, operation or maintenance of any non-experimental Class V GS well is prohibited, at
§144.15.

Commenter Name: Quinlan J. Shea Letter ID: 0177

Commenter Organization: Edison Electric Institute Comment ID: 23580

Other EPA Comment Codes and Descriptions: 2100 1.6 Target Geologic Formations for GS 

Comment: In light of the UIC permitting process’s focus on demonstrating that a project 

will not endanger USDW, EEI proposes that rather than establish a blanket 

limitation on available receiving formations, the Agency rely upon the numerous 

other provisions that serve to protect USDW and allow those provisions to 

operate in the context of actual proposed projects. In the alternative, 

limitations on receiving formations could be left to the UIC program director‘s 

discretion-bounded by appropriate standards for the exercise thereof-for a 

particular project; however, given the case-by-case nature of the permitting 

process and the requirement to demonstrate non-endangerment of USDW, providing 

for the exercise of such discretion is likely unnecessary. 

Response: As described above, EPA clarifies that the GS rule does not categorically preclude

injection of CO2 into any non-USDW formation types. The purpose of the GS rule is to ensure

protection of USDWs from endangerment, and the rule requires that owners or operators

demonstrate that wells are sited in suitable systems with geologic formations to receive and confine

injected CO2, required at §146.83 of the GS rule. If an owner or operator can demonstrate to the

Director's satisfaction that GS in coal seams, basalts, salt domes, or shales can be accomplished in a

manner that protects USDWs and meets all of the requirements of the GS rule, the project may be

permitted as a Class VI well. 

As described above, EPA acknowledges that there are limited circumstances where injection above

the lowermost USDW can be performed in a manner that protects USDWs from endangerment, as

long as appropriate protections are in place. The final GS rule at §146.95 establishes a process by

which owners or operators can seek a waiver of the Class VI injection depth requirements for

injection into non-USDW formations above and/or between USDWs. 

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23802

Comment: details, proximity to USDWs and other resources, and other factors. In addition, 

it is not necessarily the case that injection always should have to occur 

beneath the lower most water source with a confining system in place as 

suggested by EPA. This should be determined on a case-by-case basis. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to
UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23858

Other EPA Comment Codes and Descriptions: 4344 2.4.4.2.2 Comments opposed to setting a

minimum injection depth 

Comment: Geologic sequestration of CO2 need not be, in every instance, beneath the 

lowermost USDWs, nor should EPA set a minimum injection depth requirement. Such 

requirements likely would preclude injection into certain targeted geologic 

formations, which may include storage sites currently under consideration for 

GS. These formations may include unmineable coal seams, zones in between or 

above USDWs, and others. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects.

EPA believes that a determination of site-suitability for GS (i.e., that subsurface formations will

receive and confine injected CO2) should be made on a site-specific basis. The GS rule, at §146.82,

requires the owner or operator to provide extensive site- and project-specific information to the

Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be

contained within the injection formation, and that USDWs will be protected from endangerment. 

EPA believes that proper siting, monitoring, and containment capacity are critical elements of Class

VI injection for GS. However, the Agency also believes that injection into non-USDW formations

above and between USDWs presents unique challenges related to movement of CO2 in the

subsurface, which requires a unique approach to ensure that USDWs are protected. Therefore, the

Agency believes that additional requirements are appropriate and necessary for wells that would

inject into non-USDWs above and between USDWs. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to
comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25177

Other EPA Comment Codes and Descriptions: 2163 1.6.3.1 Comments in favor of injection into

unmineable coal seams 

Comment: G. As with unmineable coal seams, EPA seeks comment on prohibiting injection 

into such formations if they are above the lowermost USDW. 

NYSDEC-DMN Response: While not a likelihood in New York due to the absence of 

coal in the state and typical depths to lowermost USDWs, NYSDEC-DMN believes 

there should not be any blanket prohibition against injection into any 

potentially approvable geologic zone even if it is above the lowermost USDW. 

There may be circumstances where this is appropriate and safe. The decision to 

permit a project should be made on a site-specific basis and evaluation. 

Response: EPA agrees that GS into unmineable coal seams has the potential to allow sequestration

while ensuring USDW protection from endangerment, as described by commenters citing the process

of enhanced methane recovery. The final GS rule does not preclude injection into unmineable coal

seams provided owners or operators can demonstrate that GS can be performed in a manner that

protects USDWs from endangerment. The Agency clarifies that owners or operators of Class VI

wells used for injecting CO2 into unmineable coal seams are subject to the same site

characterization, well construction, operation, monitoring, post-injection site care and site closure

requirements that are required of projects injecting into other formation types. 

EPA clarifies that the final rule requires that injection for GS be into non-USDWs below the

lowermost USDW; however, owners or operators may apply for a waiver from this requirement, as

described in §146.95. For more information, see the discussion of waivers in the preamble to the

final rule.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24322

Comment: C. Class VI Injection Should Not be Limited to Injection Below the Lowermost 

USDW. 

The proposed rule limits Class VI injection to injection into formations that 

are below the lowermost underground source of drinking water (USDW). This 

requirement is not necessary for the protection of USDWs and would remove a 

substantial number of viable formations from consideration for GS. There are 

examples of existing CO2 injection wells (in the EOR/EGR context) that 

demonstrate that it is possible to inject CO2 above the lowermost USDW without 

causing any endangerment of USDWs. An excellent example is the Salt Creek EOR 

project in Wyoming, which has a USDW below the injection zone. The Wyoming State 

Geological Survey has already submitted comments emphasizing that restricting 

injection of CO2 only below the lowermost [SDW aquifer "will make it impossible 

to inject CO2 into deep saline aquifers in Rock Mountain Laramide [LARAMIE?] 

Basins (RMLB)." These comments go on to say: "For economic and regulatory 
purposes, the regulations as proposed will make geological sequestration of CO2 

impossible. To promulgate a geological CO2 sequestration regulation for RMLB out 

of the context of Rocky Mountain Laramide [?] geology will make it extremely 

difficult to mitigate the effects of greenhouse emissions on climate change in 

the West." Comments of Ronald Surdam, Director/State Geologist, Wyoming State 

Geological Survey (December 2008). 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

Additionally, the final GS rule does not categorically preclude or prohibit injection into any type of

formation. 

EPA believes that a determination of site-suitability for GS (i.e., that subsurface formations will

receive and confine injected CO2) should be made on a site-specific basis. The GS rule, at §146.82,

requires the owner or operator to provide extensive site- and project-specific information to the

Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be

contained within the injection formation, and that USDWs will be protected from endangerment.

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24349

Other EPA Comment Codes and Descriptions: 4344 2.4.4.2.2 Comments opposed to setting a

minimum injection depth 

Comment: 6. Injection Depth 

As already discussed, we oppose restricting Class VI injection to either to any 

minimum injection depth or to injection zones below the lowermost USDW. As EPA 

recognizes, 73 Fed. Reg. at 43511-12, such restrictions are not necessary to 

protect USDWs and would serve only to preclude the use of what might otherwise 

be appropriate CO2 storage reservoirs. EPA should permit GS under any 

circumstances in which the Director can determine that USDWs will not be 

endangered. 

Recognizing that the USDW definition is so broad as to include formations that - 

because of their location, depth, or other factors - could not reasonably be 

expected to serve as sources of drinking water, we support the appropriate use 

of aquifer exemptions to facilitate GS. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects.

EPA believes that a determination of site-suitability for GS (i.e., that subsurface formations will

receive and confine injected CO2) should be made on a site-specific basis. The GS rule, at §146.82,

requires the owner or operator to provide extensive site- and project-specific information to the

Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be
contained within the injection formation, and that USDWs will be protected from endangerment. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24363

Comment: There should not be a blanket prohibition concerning injection above USDW’s or 

at specific depths. This requirement is not necessary for the protection of 

USDWs and would remove a vast number of viable formations from consideration. It 

has been shown that it is possible to operate CO2 injection wells in an EOR 

context without endangering USDWs that are located below the injection zone. An 

excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Under the proposed rule, there are other measures that 

would provide real assurance of formation integrity and require operators to 

demonstrate that their project will not endanger USDWs, making the lowermost 

USDW restriction unnecessary. Instead, operators should be able to show adequate 

containment to prevent endangerment of USDWs both above and below the injection 

zone used for geologic sequestration. 

Response: As described above, EPA agrees that it is not appropriate to set a minimum injection

depth for GS projects and the Agency believes that a determination of site-suitability for GS (i.e.,

that subsurface formations will receive and confine injected CO2) should be made on a site-specific

basis. The GS rule, at §146.82, requires the owner or operator to provide extensive site- and projectspecific information to the Director to demonstrate that the site meets the minimum site criteria at

§146.83, that the CO2 will be contained within the injection formation, and that USDWs will be

protected from endangerment.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24386

Comment: Additionally, there should not be a blanket prohibition concerning injection 

above USDW’s or at specific depths. This requirement is not necessary for the 

protection of USDWs and would remove a vast number of viable formations from 

consideration. Industry has shown that it can operate CO2 injection wells in an 

EOR context without endangering USDWs that are located below the injection zone. 

An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

measures that would provide real assurance of formation integrity and require 
operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. Instead, operators should be able to 

show adequate containment to prevent endangerment of USDWs both above and below 

the injection zone used for geologic sequestration. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24393

Comment: Additionally, there should not be a blanket prohibition concerning injection 

above USDW’s or at specific depths. This requirement is not necessary for the 

protection of USDWs and would remove a vast number of viable formations from 

consideration. Industry has shown that it can operate CO2 injection wells in an 

EOR context without endangering USDWs that are located below the injection zone. 

An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

measures that would provide real assurance of formation integrity and require 

operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. Instead, operators should be able to 

show adequate containment to prevent endangerment of USDWs both above and below 

the injection zone used for geologic sequestration. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24405

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: Rule Provision: 146.81(d) [Definition - Geologic sequestration project] 

Proposed CCS Group Recommendations: Geologic sequestration project means an 

injection well or wells used to emplace a carbon dioxide stream beneath the 

lowermost formation containing a USDW INTO AN INJECTION ZONE EXCLUSIVELY FOR 

THE PURPOSE OF GEOLOGIC SEQUESTRATION. It includes the subsurface threedimensional extent of the carbon dioxide plume, associated pressure front, and 

displaced brine, as well as the surface area above that delineated region. 

Basis for CCS Group Comments: There should not be a blanket prohibition 

concerning injection above USDW’s or at specific depths. This requirement is not 

necessary for the protection of USDWs and would remove a vast number of viable 

formations from consideration. Industry has shown that it can operate CO2 
injection wells in an EOR context without endangering USDWs that are located 

below the injection zone. An excellent example is the Salt Creek EOR project in 

Wyoming, which has a USDW below the injection zone. Moreover, under the proposed 

rule, there are other measures that would provide real assurance of formation 

integrity and require operators to demonstrate that their project will not 

endanger USDWs, making the lowermost USDW restriction unnecessary. 

Response: EPA has revised the definition of a geologic sequestration project to account for the new

requirements to include “wells used for geologic sequestration of carbon dioxide that have been

granted a waiver of the injection depth requirements pursuant to requirements at §146.95.”

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24510

Comment: Rule Provisions or Federal Register Cite: 144.6(f), 146.5, 146.81 

EPA Preamble Question: 6. The location and proximity of other formations to 

USDWs may preclude their use for GS. EPA seeks comment on prohibiting injection 

into such formations if they are above the lowermost USDW. EPA Notice 43503. 

CSC Response: Restricting injection to formations below the lowermost 

underground source of drinking water or USDW is not necessary for the protection 

of USDWs and would remove a vast number of viable formations from consideration. 

Industry has shown that it can operate CO2 injection wells in an EOR context 

without endangering USDWs that are located below the injection zone. An 

excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

measures that would provide real assurance of formation integrity and require 

operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. 

In conjunction with this recommendation, CSC also recommends that all GS into 

basalts, coal seams, and salt domes be conducted under Class V as experimental 

wells initially and then as commercial scale Class V wells/projects as the 

experimental projects or other factors allow applicants to demonstrate that 

these sites can be suitable for geological sequestration while preventing 

endangerment of USDWs. 

Keeping these wells under Class V would allow EPA and the states to gain 

experience in developing suitable permitting requirements for such wells and to 

tailor those requirements until the agencies are ready to adapt the Class VI 

regulations or other requirements as appropriate. 

Response: EPA anticipates that some owners or operators will apply for Class V experimental

technology permits for injection into formations including shallow basalts, coal seams, salt caverns,

and shales. These formations may or may not be located above the lowermost USDW or between

USDWs. To facilitate experimental injection for GS and to increase understanding of injection into

these formation types, the Agency is amending the Class V experimental technology guidance. The

guidance will be available on EPA's web site, at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. EPA acknowledges that the Class

V experimental technology well sub-classification may be appropriate for these projects, provided
they are experimental in nature. EPA expects that, following the final GS rule, a limited number of

experimental injection projects testing GS technology will continue. EPA anticipates that these

projects will be small-scale and involve limited CO2 volumes. However, if these projects become

larger scale and are no longer experimental, they will need to be permitted as Class VI wells. The

construction, operation, or maintenance of any non-experimental Class V GS well is prohibited, at

§144.15.

Commenter Name: Jeff W. Sheets Letter ID: 0192

Commenter Organization: ConocoPhillips Comment ID: 23893

Other EPA Comment Codes and Descriptions: 3120 2.1.2 Need to identify additional confining

and containment zones (seeking comment) 

Comment: Lowermost USDW: 

EPA's proposal restricts injection to formations beneath the lowermost USDW and 

gives the Director the discretion to require identification of additional 

confining zones. ConocoPhillips recommends focus on performance standards rather 

than depth or confining zone redundancy - injection should be allowed into any 

injection zone which has geologic and mechanical isolation sufficient to prevent 

fluid movement which could endanger any USDW. In some site situations injection 

zones can be safely above USDW's with adherence to well construction standards 

and other requirements. There may be high potential geologic sites above USDWs 

which need not be excluded for storage. Identification of redundant confining 

zones may be confusing and unduly reduce the number of sites deemed appropriate 

for CCS. This is particularly true since the definition of confining zone 

includes "formation or set of formations." 

Response: EPA clarifies that secondary confining zones are not required for all GS sites. Rather,

secondary confining zones are required when the Director determines that these zones are needed to

maximize the protection of USDWs from endangerment. EPA retains the requirement to identify

additional containment/confining zones, if required by the Director, as proposed (e.g., §146.83(b)).

EPA believes that, in some situations, the presence of additional confining and containment zones

above the primary (i.e., lowermost) confining zone can improve USDW protection. These layers

could further impede vertical fluid movement and allow for pressure dissipation, and also provide

additional sites for monitoring, mitigation, and remediation. EPA also believes that a site-specific

demonstration regarding the need for additional confining zones affords the flexibility the

commenter seeks. 

EPA adds that the final GS rule contains a provision (at 146.95) for owners or operators to apply for

waivers from the requirement that injection be below the lowermost USDW. EPA believes this

waiver provision will reduce potential limitations on the re-permitting of Class II wells as Class VI

wells, provided they meet the requirements at 146.95 while still protecting USDWs from

endangerment.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the
Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: John R. Baza Letter ID: 0193

Commenter Organization: Utah Division of Oil, Gas, and Mining Comment ID: 23911

Comment: Injection Zones for Gas Sequestration 

EPA has proposed that all injection of CO2 for sequestration should be below the 

lowermost USDW. This proposal is too restrictive and could eliminate many areas 

of potential injection throughout the State of Utah that might otherwise be 

considered for sequestration. There should be no prohibition against injection 

into any zone even if above the lowermost USDW as long as it can be determined 

that geologic conditions would prevent endangerment to a USDW. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high-quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Paul Pike Letter ID: 0198

Commenter Organization: Ameren Corporation Comment ID: 23950

Other EPA Comment Codes and Descriptions: 4410 2.4.4.3.1 Comments in favor of allowing

injection above/between USDWs in certain circumstances; 4460 2.4.4.4.1 Comments in favor of

allowing aquifer exemptions in certain circumstances 

Comment: INJECTION WELL OPERATING REQUIREMENTS 

Ameren supports allowing injection between and/or above the lowermost USDW, 

provided that the Class VI wells can be shown that their operations will be 

protective of USDWs. 73 Fed. Reg. at 43512. This could be particularly 

important in areas of the country with deep USDWs, where an absolute requirement 

that Class VI wells be constructed beneath the lowermost USDW could render the 
program impractical. We also support this approach in areas where it can be 

shown that geologic conditions would prevent fluid movement into adjacent USDWs. 

Id. Therefore, we oppose an absolute prohibition on use of exempt aquifers for 

Class VI injection; again use of exempt aquifers could be permitted where the 

specific aquifer exemption criteria are satisfied. Id. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24564

Comment: Injection below the lowermost USDW: 

A prohibition on injection above the lowermost USDW is not necessary for the 

protection of USDWs. Injection operations currently take place above a USDW in 

multiple classes, including current EOR projects. This regulation would 

eliminate many excellent sequestration formation candidates, especially in the 

western region of the United States. In addition, the regulations already 

provide for protection of USDWs both above and below the injection zone. Through 

proper siting and well design, risks to any USDW can be minimized. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency
believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. 

For additional information on the waiver approach, please see the final rule and preamble as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24573

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 

EPA Rule Issue: 6. The location and proximity of other formations to USDWs may 

preclude their use for GS. EPA seeks comment on prohibiting injection into such 

formations if they are above the lowermost USDW. EPA Notice 43503. 

Anadarko Petroleum Corporation (APC) Response: Restricting injection to 

formations below the lowermost underground source of drinking water or USDW is 

not necessary for the protection of USDWs and would remove a vast number of 

viable formations from consideration. Industry has shown that it can operate CO2 

injection wells in an EOR context without endangering USDWs that are located 

below the injection zone. An excellent example is the Salt Creek EOR project in 

Wyoming, which has a USDW below the injection zone. Moreover, under the proposed 

rule, there are other measures that would provide real assurance of formation 

integrity and require operators to demonstrate that their project will not 

endanger USDWs, making the lowermost USDW restriction unnecessary. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24626

Comment: Additionally, there should not be a blanket prohibition concerning injection 

above USDW’s or at specific depths. This is especially true given the 

possibility of changes in the definition of a USDW to include formations greater 

than 10,000 parts per million Total Dissolved Solids. This requirement is not 

necessary for the protection of USDWs and would remove a vast number of viable 

formations from consideration. Industry has shown that it can operate CO2 

injection wells in an EOR context without endangering USDWs that are located 
below the injection zone. An excellent example is the Salt Creek EOR project in 

Wyoming, which has a USDW below the injection zone. Moreover, under the proposed 

rule, there are other measures that would provide real assurance of formation 

integrity and require operators to demonstrate that their project will not 

endanger USDWs, making the lowermost USDW restriction unnecessary. 

Response: As described above, EPA agrees that it is not appropriate to set a minimum injection

depth for GS projects and the Agency believes that a determination of site-suitability for GS (i.e.,

that subsurface formations will receive and confine injected CO2) should be made on a site-specific

basis. The GS rule, at §146.82, requires the owner or operator to provide extensive site- and projectspecific information to the Director to demonstrate that the site meets the minimum site criteria at

§146.83, that the CO2 will be contained within the injection formation, and that USDWs will be

protected from endangerment.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24628

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 2046

1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ dividing line between Class

II and Class VI (seeking comment) 

Comment: Rule Provision: 144.80 

Anadarko Petroleum Corporation (APC) Comments: (b) Class II. Wells which inject 

fluids:........(2) for enhanced recovery of oil or natural gas; (3) FOR EOR OR 

EGR, AND WHERE GEOLOGIC SEQUESTRATION OF A CARBON DIOXIDE STREAM IS

OCCURRING 

DURING OR IN CONNECTION WITH EOR OR EGR OPERATIONS OR ACTIVITIES; and (4)

For 

storage of hydrocarbons.... 

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon 

dioxide STREAMS. WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2 STREAMS

OCCURS DURING 

OR IN CONNECTION WITH EOR OR EGR ARE REGULATED UNDER CLASS II. 

Rationale: See 144.6 

Rule Provision: 146.5 

Anadarko Petroleum Corporation (APC) Comments: b) Class II. Wells which inject 

fluids:..... (4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC 

SEQUESTRATION IS OCCURRING DURING OR IN CONNECTION WITH ENHANCED

RECOVERY OF OIL 

OR NATURAL GAS PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE

THAN 

INSIGNIFICANT FUTURE PRODUCTION VOLUMES OR RATES AS A RESULT OF

CARBON DIOXIDE 

INJECTION AND (II) OPERATING PRESSURES ARE NO HIGHER THAN REASONABLY

NECESSARY 

TO PRODUCE SUCH VOLUMES OR RATES; AND 
(5) FOR GEOLOGIC SEQUESTRATION IN SUBSURFACE GEOLOGIC FORMATIONS IN

WHICH 

EXTRACTION OF HYDROCARBONS HAS OCCURRED, IS OCCURRING OR IS

REASONABLY EXPECTED 

TO OCCUR AND WHERE THE CRITERIA OF PARAGRAPH (B)(4) ARE NOT MET. 

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon 

dioxide STREAMS. Beneath the lowermost formation containing an underground 

source of drinking water (USDW). WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2 

STREAMS OCCURS DURING OR IN CONNECTION WITH EOR OR EGR ARE REGULATED

UNDER CLASS 

II. 

Rationale: See 144.6 

Response: As described above in the response to comment 24625 regarding the suggested edit at

144.6, EPA did not make the suggested change. The Agency disagrees that wells injecting CO2 for

the primary purpose of long-term storage should be regulated under Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and

preamble for further discussion on EPA's final approach to transitioning from Class II to Class VI.

As described above, the final GS rule at §146.95 establishes a process by which owners or operators

can seek a waiver of the Class VI injection depth requirements for injection into non-USDW

formations above and/or between USDWs. 

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24635

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 4400

2.4.4.3 Allowing injection above or between USDWs (seeking comment) 

Comment: Rule Provision: 146.81(d) [Definition - Geologic sequestration] 

Anadarko Petroleum Corporation (APC) Comments: Geologic sequestration project 

means an injection well or wells used to emplace a carbon dioxide stream 

beneath the lowermost formation containing a USDW INTO AN INJECTION ZONE 

EXCLUSIVELY FOR THE PURPOSE OF GEOLOGIC SEQUESTRATION. It includes the 

subsurface three-dimensional extent of the carbon dioxide plume, associated 

pressure front, and displaced brine, as well as the surface area above that 

delineated region. 

Rationale: There should not be a blanket prohibition concerning injection above 

USDW’s or at specific depths. This requirement is not necessary for the 

protection of USDWs and would remove a vast number of viable formations from 

consideration. Industry has shown that it can operate CO2 injection wells in an 

EOR context without endangering USDWs that are located below the injection zone. 

An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 
measures that would provide real assurance of formation integrity and require 

operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. 

Response: EPA has revised the definition of a geologic sequestration project to account for the new

requirements to include “wells used for geologic sequestration of carbon dioxide that have been

granted a waiver of the injection depth requirements pursuant to requirements at §146.95.”

Commenter Name: Chris M. Hobson Letter ID: 0201

Commenter Organization: Southern Company Comment ID: 22162

Comment: Area of Review ("AoR") and Corrective Action 

Southern Company encourages EPA to avoid arbitrary absolutes or blanket 

prohibitions in the Final Rule and to instead craft regulations allowing Class 

VI permit applicants and Directors to focus on scientific data and technical 

demonstrations in characterizing potential geologic sequestration sites. It is 

premature to categorically preclude injection in certain types of formations as 

CO2 injection and sequestration technology may develop to make injection in 

those formations feasible while still protecting against endangerment of USDWs. 

A recent report by the Government Accountability Office ("GAO") predicts a 

demand for thousands, if not tens of thousands, of UIC permits to accommodate 

the volumes of CO2 to be captured once CCS is deployed on a commercial scale. 

Climate Change - Federal Actions Will Greatly Affect the Viability of Carbon 

Capture and Storage as a Key Mitigation Option, GAO-08-1080 at 40 (September 

2008) ("GAO Report"). Given the likelihood for such demand, EPA should encourage 

the identification and utilization of as many injection zones as possible, 

provided that the Director determines that injection in a given site would be 

protective of USDWs before issuing a permit for injection at that site. 

To maximize capacity for CO2 injection that is protective of USDWs, the Final 

Rule should avoid arbitrary exclusions of whole categories of injection zones. 

For example, a requirement that all injection zones be located below the 

lowermost USDW is unnecessary; there may be situations in which injection can 

occur above the lowermost USDW without endangering USDWs - for example, in 

current oil and gas reservoirs with demonstrated trapping capabilities. ¡d. at 

43512. In situations where the Owner or Operator could not demonstrate that 

injection above the lowermost USDW could occur without endangering USDWs, the 

permit could preclude injection into such formations. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity
limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. 

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Christopher Murray Letter ID: 0207

Commenter Organization: Pacific Northwest National Laboratory Comment ID: 22437

Comment: Stratigraphic Restriction of Saline and Other Reservoirs to Below the Lowermost

USDW. . . .Page 12 

GS should be permitted in the following: 1) reservoirs containing >10,000 mg/L 

TDS, 2) where the formation water is <10,000 mg/L but non potable for other 

reasons, or 3) formations exempted as USDWs by the state. We do not support the 

proposed restriction of GS to stratigraphic zones below the lowermost USDW. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

Additionally, the final GS rule does not categorically preclude or prohibit injection into any type of

formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. 

For additional information on the waiver approach and aquifer exemptions for Class VI wells, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Christopher Murray Letter ID: 0207
Commenter Organization: Pacific Northwest National Laboratory Comment ID: 22448

Other EPA Comment Codes and Descriptions: 4340 2.4.4.2 Minimum injection depth (seeking

comment); 4430 2.4.4.3.3 Injection into coal seams above USDWs (seeking comment) 

Comment: Stratigraphic Restriction of Saline and Other Reservoirs to Below Lowermost USDW 

PROPOSED REGULATION FOR SALINE FORMATIONS 

p. 43494, c. 2 Saline formations: Deep and geographically extensive sedimentary 

rock layers saturated with waters or brines that have a high total dissolved 

solids (TDS) content (i.e., >10,000 mg/L TDS). 

p. 43505, c. 1 1. Proposed Geologic Siting Requirements Existing UIC 

requirements for siting injection wells include identification of geologic 

formations suitable to receive the injected fluids and confine them such that 

they are isolated below the lowermost USDWs, minimizing the potential for 

endangerment. 

p. 43502-43503, section Hon target geologic formations As with unmineable coal 

seams, EPA seeks comment on prohibiting injection into such formations [basalts, 

salt domes, and shales] if they are above the lowermost USDW. 

The EPA is soliciting comments on these issues: 

1. Whether CO2 injection should be allowed into an injection zone (saline 

sedimentary formations, unminable coal seam, basalt, salt caverns, shales, or 

other reservoirs) above the lowermost USDW, when the Director determines that 

geologic conditions exist that will prevent fluid movement into adjacent USDWs. 

2. Whether a designated USDW should be exempted to allow for GS, and under what 

conditions should these exemptions be approved. 

3. Whether all USDWs should be exempted below a CO2 injection receiving bed. 

4. Whether the EPA should set a minimum injection depth requirement for GS, 

rather than require that such injection take place below the lowermost USDW. 

DISCUSSION 

Three of the most important issues here are (a) the physical location of saline 

formations or other types of geologic reservoirs for GS, relative to USDWs; (b) 

under what circumstances the EPA should remove one or more water-bearing zones 

from the list of USDWs to allow injection; and (c) under what other conditions 

should the EPA allow injection above a USDW. 

In addition to injection into saline formations, EPA recognizes that basalt, 

unmineable coal seams, salt domes, abandoned mines, black shales and other types 

of reservoirs may be promising emerging targets. Basalts, in particular appear 

to have considerable potential for GS Research by PNNL and others indicates that 

extruded basalt flow tops and flow bases may have considerable potential for GS. 

Research by PNNL and others indicates that extruded basalt flow tops and flow 
bases may have regional, multi-gigaton capacity for CO2 storage. In addition, 

laboratory experiments suggest that regional, multi-gigaton capacity for CO2 

storage. mineralization of large volumes of CO2 may proceed within a few years 

of injection (McGrail et al, 2006). 

In the proposed rule, the new Class VI wells would be allowed to inject CO2 into 

basalts, deep saline reservoirs, and other potential reservoirs only when they 

are beneath the lowermost USDW. 

A USDW is defined by the EPA as "An aquifer or portion of an aquifer that 

supplies any public water system or that contains a sufficient quantity of 

ground water to supply a public water system, and currently supplies drinking 

water for human consumption, or that contains fewer than 10,000 mg/1 total 

dissolved solids and is not an exempted aquifer." This definition would include 

many non-potable aquifers that would be candidates for GS. 

The EPA's reliance on the standard definition of a USDW as being solely <10,000 

mg/L TDS is far too restrictive. In many states, this standard is not applied - 

all groundwaters are protected regardless of water quality. In at least one 

state GS operations would be permitted if removing anthropogenic CO2 is 

considered a greater public benefit than the loss of a marginal aquifer. 

The EPA is aware that restricting GS to a position below all EPA defined USDWs 

would severely limit GS in many areas. Under the current proposed rule, directors 

may grant injection into deep, marginal USDWs that directly overlie crystalline 

basement rock and/or unmineable coal seams. In addition to these exceptions, the 

EPA would consider allowing operation of GS wells where receiving formations are 

above the lowermost USDW only where there are thousands of feet between the 

injection zone and the overlying and underlying USDWs. 

REFERENCES 

McGrail, B. P., H. T. Schaef, A. M. Ho, Y. Chien, J. J. Dooley, and C. L. 

Davidson. 2006. Potential for Carbon Dioxide Sequestration in Flood Basalts, J. 

Geophys. Res. 111, B12201. 

Response: Regarding injection into basalts, coal seams, and salt domes, EPA clarifies that the GS

rule does not categorically preclude injection of CO2 into any non-USDW formation types. The

purpose of the GS rule is to ensure protection of USDWs from endangerment, and the rule requires

that owners or operators demonstrate that wells are sited in suitable systems with geologic

formations to receive and confine injected CO2, as required at §146.83 of the GS rule. The Class VI

siting, well construction and operation, monitoring and testing, and post-injection site care and site

closure requirements are designed to ensure that injected CO2 remains within the target formation. If

an owner or operator can demonstrate to the Director's satisfaction that GS in coal seams, basalts,

salt domes, or shales can be accomplished in a manner that protects USDWs and meets all of the

requirements of the GS rule, the project may be permitted as a Class VI well. 

EPA acknowledges that there may be unknown risks associated with GS, particularly regarding GS

into formations such as coal seams, basalts, and salt domes, which have been the subject of limited

experimental projects in the past. EPA anticipates that in the short-term, GS into these types of
formations will continue to be experimental (i.e., if they are to test GS technologies and collect data),

and will likely be permitted as Class V experimental technology wells and be subject to UIC

Program Guidance #83. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs. The final GS rule at §146.95 establishes a

process by which owners or operators can seek a waiver of the Class VI injection depth

requirements. The waiver approach requires the submission of extensive, site-specific information

(in conjunction with the permit application submittal) to demonstrate that injection of CO2 into a

formation that is above or between USDWs can be done in a manner that is protective of USDWs.

The requirements are designed to ensure the owner or operator, the Director, and the Regional

Administrator consider, on a site specific basis, the implications, benefits, and challenges associated

with GS and ensuring water availability and USDW protection.

EPA is not changing the USDW definition; changing the definition of a USDW is outside the scope

of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as required under the

SDWA, by establishing regulations to ensure the safe injection of CO2 for long-term storage. 

EPA believes that there is increasing demand for water resources and that technology improvements

may make high TDS aquifers viable drinking water sources. EPA believes these potential resources

should be considered when injection depth waivers are sought. Therefore, the final GS rule at

§146.95(b) requires the Director to consider these issues in determining whether an injection depth

waiver is appropriate. Specifically, the Director must consider whether alternative injection sites are

available; community needs, demands, and supply from drinking water resources; planned needs,

potential and/or future use of USDWs and non-USDWs in the area; and a plan for securing

alternative resources or treating USDW formation waters in the event of contamination related to the

Class VI injection activity.

Commenter Name: Christopher Murray Letter ID: 0207

Commenter Organization: Pacific Northwest National Laboratory Comment ID: 22450

Comment: The EPA suggests the following possible alternatives that would allow injection 

between USDWsor above the lowest USDW: 

1 . Injection approval for GS between USDWs formations is at the Director's 

discretion in circumstances in which it maybe demonstrated that USDWs wouldnot be 

endangered. 

2. Directors may be allowed to exempt, at their discretion, all USDWs below a GS 

injection zone. (This would permanently remove these aquifers from protection as 

USDWs). 

PNNL RECOMMENDATION 
GS should be permitted in the following: 

1) reservoirs containing >10,000 mg/1L TDS, 2) where the formation water is 

<10,000 mg/L but is non-potable for other reasons, or 3) formations exempted as 

USDWsby the state. 

We do not support the proposed restriction of GS to stratigraphic zones below 

the lowermost USDW. 

- Prohibition of CO2 injection into saline formations above USDWs is overly 

restrictive and would severely limit GS in states such as Wyoming, where deep 

sedimentary formations in much of the state have TDS lower than 10,000 mg/1 

(NETL). Thus almost any formation considered for GS would likely overlie a low 

TDS formation. 

- GS should be allowed into an injection zone above the lowermost USDW (whether 

saline or other formation) when the Director determines that geologic conditions 

exist that will prevent fluid movement into nearby USDWs. Conditions that will 

prevent downward movement of fluids include the presence of intact low 

permeability beds between the receiving bed and the underlying USDW. In 

consideration of the buoyant behavior of injected CO2, the requirement of 

thousands of feet of intervening formations may be less important than the 

demonstration of the sealing capacity of the intervening layers. We believe that 

"thousands of feet" is a vague requirement, when the more rigorous test is the 

demonstration of the sealing capacity of the intervening layers. 

- The draft rule is far too restrictive and is not based on technical risk 

factors. Risk of CO2 contamination to a USDW is lower for aquifers that underlie 

an injection reservoir due to the inherent buoyancy of the CO2. Vertical migration 

can be interrupted completely by the presence of one or more low permeability 

layers. Hence, a prohibition on injecting above the shallowest USDWis not based 

on real technical risk of a GS project. 

NETL. 2007. National Carbon Sequestration Atlas. 

http://www.netl.doe.gov/technologies/carbon seq/refshelf/atlas/index.html 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs. The final rule

also establishes limited circumstances under which expansions of the areal extent of aquifer

exemptions may be granted for owners or operators of Class II EOR/EGR wells transitioning to

Class VI injection for GS.

Commenter Name: Richard Guinn Letter ID: 0210

Commenter Organization: Eastman Chemical Company Comment ID: 22696

Comment: 5. CO2 injection should not be restricted only to formations below the lowermost 

underground source of drinking water. 
Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs.

Commenter Name: Richard Guinn Letter ID: 0210

Commenter Organization: Eastman Chemical Company Comment ID: 22711

Comment: Concern #5: Restriction of injection to formations below the lowermost 

underground source of drinking water or USDW. (Ref: page 43512, 3. Proposed 

Injection Well Construction Requirements) 

This requirement is not necessary for the protection of USDWs. It is in-fact 

overly restrictive and will eliminate many suitable and safe geologic formations 

for CO2 sequestration or permanent storage. It will also render geological 

storage impractical (pumping power and well costs) for states in the western 

United States where the drinking water aquifers are many thousands of feet deep 

and well isolated from overlying regions. Also, industry has demonstrated that 

it can operate CO2 injection wells for EOR without endangering USDWs that are 

located below the injection zone (e.g., the Salt Creek EOR project in Wyoming, 

having a USDW below the injection zone). Concern #6 Demonstration of financial 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Richard Guinn Letter ID: 0210

Commenter Organization: Eastman Chemical Company Comment ID: 22734

Other EPA Comment Codes and Descriptions: 4344 2.4.4.2.2 Comments opposed to setting a

minimum injection depth 

Comment: EPA seeks comment on whether the Agency should set a minimum injection depth 
requirement for CO2 GS, rather than require that such injection take place below 

the lowermost USDW. EPA Notice 93. 

EPA should neither require injection below the lowermost USDW nor alternately 

require a minimum depth requirement as geologic structures are likely to be 

encountered that provide for secure and safe storage. Examples of such storage 

that should be acceptable are domes and caverns. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: John King Letter ID: 0211

Commenter Organization: Shell Exploration and Production Company

(SEPCo)

Comment ID:

22747

Comment: - Lowermost USDW: 

- Injection above the lowest USDW should be allowed but the operator should be 

required to demonstrate confinement above and below the injection formation. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying

information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements

to ensure USDW protection above and below the injection zone. 

EPA believes that proper siting, monitoring, and containment capacity are critical elements of Class
VI injection for GS. However, the Agency also believes that injection into non-USDW formations

above and between USDWs presents unique challenges related to movement of CO2 in the

subsurface, which requires a unique approach to ensure that USDWs are protected. Therefore, the

Agency believes that additional requirements are appropriate and necessary for wells that would

inject into non-USDWs above and between USDWs, including demonstration of confinement above

and below the injection zone.

Commenter Name: John King Letter ID: 0211

Commenter Organization: Shell Exploration and Production Company

(SEPCo)

Comment ID:

22761

Comment: E. Lowermost USDW Restriction 

The proposed rule limits Class VI injection to injection into formations that 

are below the lowermost underground source of drinking water (USDW). This 

requirement is not necessary for the protection of USDWs and would remove a vast 

number of viable formations(SEE FOOTNOTE 1) from consideration for GS. Industry 

has shown that it can operate CO2 injection wells in an EOR/EGR context without 

endangering USDWs that are located below the injection zone. An excellent 

example is the Salt Creek EOR project in Wyoming, which has a USDW below the 

injection zone. Moreover, under the proposed rule, there are other measures that 

would provide real assurance of formation integrity and require operators to 

demonstrate that their project will not endanger USDWs, making the lowermost 

USDW restriction unnecessary. 

Recommendation: 

Injection above the lowest USDW should be allowed but the operator must 

demonstrate confinement above and below the injection formation. 

1) Referring to the Weyburn project, EPA has noted, "The conclusions of Phase I 

of the project are that depleted oil and gas reservoirs from EOR operations are 

a promising CO2 storage option ..." 73 Fed. Reg at 43500. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs. It establishes:

1) requirements specifying information that owners or operators must submit, and Directors must

consider, in consultation with PWSS Directors; 2) procedures for public notice of a waiver

application and for Director-Regional Administrator communication; 3) the waiver issuance process;

and, 4) additional requirements that apply to owners or operators of Class VI wells granted a waiver

of the injection depth requirements to ensure USDW protection above and below the injection zone. 

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Barbara Walz Letter ID: 0216
Commenter Organization: Tri-State Generation and Transmission Association,

Inc.

Comment ID:

22970

Comment: drinking water (USDW). Tri-State supports alternative approaches that would allow 

injection between and/or above the lowermost USDW, increasing capacity for 

CO2 geologic sequestration, as long as it can be demonstrated that injection will 

be protective of USDWs and meet other applicable conditions for Class VI CO2 

geologic sequestration wells. The final rule should not contain a blanket 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying

information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements

to ensure USDW protection above and below the injection zone. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Edward Steadman Letter ID: 0220

Commenter Organization: The Energy and Environmental Research Center at the

University of North Dakota

Comment ID:

21623

Comment: Page 43512. Injection Depth in Relation to USDWs. 

The requirement to be below the lowest USDW is not needed and should be 

evaluated on a site-specific basis. Furthermore, minimum depths should not be 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Such determinations would be made on a

site-specific basis.
Commenter Name: Edward Steadman Letter ID: 0220

Commenter Organization: The Energy and Environmental Research Center at the

University of North Dakota

Comment ID:

21630

Comment: Page 43535. § 146.5 Classification of injection wells. Class VI wells should not 

be limited to injections beneath the lowermost formation containing a USDW. This 

is too restrictive in some areas. For instance, consider as an example the Lower 

Cretaceous Dakota Group in the North Dakota portion of the Williston Basin. On 

the eastern margin of the Williston Basin in North Dakota, the water within the 

Dakota Group contains total dissolved solid (TDS) concentrations well below 

10,000 parts per million (ppm), and the formation therefore qualifies as a USDW. 

However, hundreds of miles to the west and southwest, near the center and 

southwestern flanks of the Williston Basin, the Dakota Group has TDS 

concentrations well above 10,000 ppm, and it is used extensively as an injection 

disposal zone for oil field produced waters. The demonstrated injectivity of the 

Dakota Group and its unsuitability as a potential USDW in western North Dakota 

make it an attractive target for industries seeking to geologically store large 

volumes of CO2. A strict, literal interpretation of the proposed rule could 

unreasonably preclude the Dakota Group from being considered as a potential 

target zone for CO2 storage. It is likely that similar examples of this scenario 

could be found in many other sedimentary basins. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying

information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements

to ensure USDW protection above and below the injection zone. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Darrick Eugene Letter ID: 0223

Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23968

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 
Comment: The TxCCSA also comments on the definition of Geologic Sequestration Project 

referenced in this section. 

Geologic sequestration project means an injection well or wells used to 

emplace a carbon dioxide stream beneath the lowermost formation 

containing a USDW. It includes the subsurface three-dimensional extent 

of the carbon dioxide plume, associated pressure front, and displaced 

brine, as well as the surface area above that delineated region. 

This definition restricts geologic sequestration projects to the lowermost 

formation containing a USDW. Restricting injection formations to the lowermost 

USDW is not necessary for the protection of USDWs and would remove a vast number 

of viable formations from consideration. The drilling industry has shown that it 

can operate CO2 injection wells in an enhanced oil recovery (EOR) context 

without endangering USDWs that are located below the injection zone. There 

should be no blanket prohibition against injection into any approved geologic 

zone even if above the lowermost USDW. The decision should be site-specific and 

based on evaluation of local geology. We fully support the change proposed by 

the Texas Railroad Commission in its comments. 

Geologic sequestration project means an injection well or wells used to 

emplace a carbon dioxide stream beneath the lowermost formation 

containing a USDW, OR ANOTHER FORMATION, IF THE DIRECTOR DETERMINES THAT 

INJECTION INTO THE OTHER FORMATION WILL NOT ENDANGER USDWS. It includes 

the subsurface three- dimensional extent of the carbon dioxide plume, 

associated pressure front, and displaced brine, as well as the surface 

area above that delineated region. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying

information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements

to ensure USDW protection above and below the injection zone. 

EPA also revised the definition of a geologic sequestration project to account for the new

requirements to include “wells used for geologic sequestration of carbon dioxide that have been

granted a waiver of the injection depth requirements pursuant to requirements at §146.95.”

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to
concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21687

Comment: (v) EPA Should Not Restrict Injection To Below Lower-Most USDW 

The Proposed Rule restricts injection of CO2 to below the lowermost USDW. (See 

§§ 144.6(f), 146.5(f) and 146.81.) EPA acknowledges that such a restriction 

would preclude the consideration and use of various potential storage sites, and 

has requested comment on this approach. 

HEI disagrees with such a blanket restriction, one that would pose a barrier to 

many, viable storage sites. The imposition of an artificial constraint limiting 

injection only to reservoirs below the USDW is not justified by technical 

knowledge or historical industry experience. For example, Class II requirements 

have proven successful in protecting USDWs even though injection into certain 

reservoirs has occurred above the lower-most USDW. Given the EPA’s effort in 

adopting a general performance-based approach, injection should be allowed to 

proceed into acceptable reservoirs provided the reservoir is demonstrated to 

provide secure CO2 storage above and below the injection formation. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Tiffany Rau Letter ID: 0224
Commenter Organization: Hydrogen Energy International Comment ID: 21690

Other EPA Comment Codes and Descriptions: 4344 2.4.4.2.2 Comments opposed to setting a

minimum injection depth 

Comment: In summary, EPA should not mandate a requirement of injection only below the 

lower-most USDW nor a minimum depth for injection of CO2. Such a comprehensive 

prohibition would unjustifiably exclude potential storage sites that do not pose 

an endangerment to USDWs. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21738

Comment: (v) EPA Should Not Restrict Injection To Below Lower-Most USDW 

The Proposed Rule restricts injection of CO2 to below the lower-most USDW. (See 

§§ 144.6(f), 146.5(f) and 146.81.) EPA acknowledges that such a restriction 

would preclude the consideration and use of various potential storage sites, and 

has requested comment on this approach. 

BP disagrees with such a blanket restriction, one that would pose a barrier to 

many, viable storage sites. The imposition of an artificial constraint limiting 

injection only to reservoirs below the USDW is not justified by technical 

knowledge or historical industry experience. For example, Class II requirements 

have proven successful in protecting USDWs even though injection into certain 

reservoirs has occurred above the lower-most USDW. Given the EPA’s effort in 

adopting a general performance-based approach, injection should be allowed to 

proceed into acceptable reservoirs provided the reservoir is demonstrated to 

provide secure CO2 storage above and below the injection formation. 

Response: EPA acknowledges that there are limited circumstances where injection above the
lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21741

Other EPA Comment Codes and Descriptions: 4344 2.4.4.2.2 Comments opposed to setting a

minimum injection depth 

Comment: In summary, EPA should not mandate a requirement of injection only below the 

lower-most USDW nor a minimum depth for injection of CO2. Such a comprehensive 

prohibition would unjustifiably exclude potential storage sites that do not pose 

an endangerment to USDWs. 

Response: As described above, EPA agrees that it is not appropriate to set a minimum injection

depth for GS projects and the Agency believes that a determination of site-suitability for GS (i.e.,

that subsurface formations will receive and confine injected CO2) should be made on a site-specific

basis. EPA also acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs, as long as appropriate

protections are in place. The final GS rule at §146.95 establishes a process by which owners or

operators can seek a waiver of the Class VI injection depth requirements for injection into nonUSDW formations above and/or between USDWs.

Commenter Name: Andrew Duguid Letter ID: 0226

Commenter Organization: Schlumberger Carbon Services Comment ID: 23997

Comment: 2. Schlumberger feels that the general prohibition on CO2 injection above the 

lowermost USDW should removed from the regulations. We feel that as long as the 

injection will not endanger USDWs the elevation with respect to the lowermost 

USDW is not important. However, if CO2 injection is allowed above the lowermost 

USDW we feel that the EPA must specify that there needs to be a confining unit 

both above and below the injection zone that is free of pathways that may allow 

for leakage of fluids out of the injection zone. The inclusion of a lower 

confining unit will be important because CO2-saturated brine or water is more 
dense than the native formation fluid and will sink. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying

information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements

to ensure USDW protection above and below the injection zone. 

EPA agrees that proper siting, monitoring, and containment capacity are critical elements of Class VI

injection for GS. However, the Agency also believes that injection into non-USDW formations above

and between USDWs presents unique challenges related to movement of CO2 in the subsurface,

which requires a unique approach to ensure that USDWs are protected. Therefore, the Agency

believes that additional requirements are appropriate and necessary for wells that would inject into

non-USDWs above and between USDWs. 

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Andrew Duguid Letter ID: 0226

Commenter Organization: Schlumberger Carbon Services Comment ID: 24006

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: §144.6 Classification of wells. 

Proposed Rule:(f) Class VI. Wells used for geologic sequestration of carbon 

dioxide beneath the lowermost formation containing a USDW. 

Schlumberger Suggested Revision: (f) Class VI. Wells used for geologic 

sequestration of carbon dioxide. 

Schlumberger Rationale: We feel that sequestration can be conducted safely above 

USDWs as evidenced by the class 2 EOR experience. Also, the restriction to below 

the lowest USDW rules out many potential CCS sites. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying

information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements

to ensure USDW protection above and below the injection zone. 
EPA adds that it has revised the definition of a Class VI well to read as follows: “Wells that are not

experimental in nature that are used for geologic sequestration of carbon dioxide beneath the

lowermost formation containing a USDW; or, wells used for geologic sequestration of carbon

dioxide that have been granted a waiver of the injection depth requirements pursuant to requirements

at §146.95 of this chapter; or, wells used for geologic sequestration of carbon dioxide that have

received an expansion to the areal extent of an existing Class II enhanced oil recovery or enhanced

gas recovery aquifer exemption pursuant to §§146.4 of this chapter and 144.7(d).”

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Andrew Duguid Letter ID: 0226

Commenter Organization: Schlumberger Carbon Services Comment ID: 24008

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: §146.5 Classification of injection wells. 

Proposed Rule:(f) Class VI. Wells used for geologic sequestration of carbon 

dioxide beneath the lowermost formation containing an underground source of 

drinking water (USDW). 

Schlumberger Suggested Revision: (f) Class VI. Wells used for geologic 

sequestration of carbon dioxide. 

Schlumberger Rationale: We feel that sequestration can be conducted safely above 

USDWs as evidenced by the class 2 EOR experience. Also, the restriction to below 

the lowest USDW rules out many potential CCS sites. 

Response: Please see the response to the commenter’s suggested revision to §144.6(f).

Commenter Name: Ben Yamagata Letter ID: 0227

Commenter Organization: Coal Utilization Research Council Comment ID: 21788

Comment: Well Construction 

The requirement that injection be allowed only beneath the lowermost formation 

containing a USDW may exclude numerous formations that would otherwise make 

excellent GS well candidates. It may be that protection of USDWs is not a 

function of whether the GS injection zone is above or below groundwater, 

especially since buoyant CO2 is more likely to rise upward than to seep 

downward. We recommend that the regulation simply require that the permit 

applicant demonstrate that the CO2 plume will not result in contamination of an 

USDW. 

Also, initial GS projects may utilize CO2 for enhanced oil recovery (EOR) or 

enhanced coal-bed methane recovery (ECGM) operations and then later convert to 

purely CO2 storage operations. Many of those operations may be above the 

lowermost USDW. 
Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

The rule establishes: 1) requirements specifying information that owners or operators must submit,

and Directors must consider, in consultation with PWSS Directors; 2) procedures for public notice of

a waiver application and for Director-Regional Administrator communication; 3) the waiver issuance

process; and, 4) additional requirements that apply to owners or operators of Class VI wells granted

a waiver of the injection depth requirements to ensure USDW protection above and below the

injection zone. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Robert E. Carter Jr. Letter ID: 0236

Commenter Organization: Indiana Department of Natural Resources (IDNR) Comment ID: 29219

Comment: States like Indiana with a proven track record of effectively managing similar 

programs have indeed demonstrated an ability to adapt to evolving technologies 

and we believe do possess the capability to effectively address long-term 

storage issues. In fact, as indicated earlier in our comments, many of the longterm issues associated with CCGS operations will be outside the purview of the 

UIC Program and will need to be addressed by states as they enact appropriate 

CCGS legislation. EPA should consider implementing rules which afford states 

with the greatest flexibility to select regulatory options that are best suited 

to their specific needs and conditions. Specific examples of requirements that 

may be too prescriptive include: 

4. Blanket prohibition of GS in zones above the lowermost USDW. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment. The

final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver of the

Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The final rule also establishes limited circumstances under which expansions of
the areal extent of aquifer exemptions may be granted for owners or operators of Class II EOR/EGR

wells transitioning to Class VI injection for GS. Additionally, the final GS rule does not categorically

preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who will undertake CO2 injection for GS. The

Agency believes this approach: 1) responds to concerns about local and regional geologic storage

capacity limitations imposed by the proposed injection depth requirements; 2) allows for a more sitespecific assessment of injection depth for GS projects; 3) accommodates injection into different

formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between

USDWs when appropriate and where it can be demonstrated that USDWs will be protected; and 5)

responds to concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to

addressing injection depth variability through a waiver process responds to concerns about future

drinking water resource availability and the need to ensure that high quality water remains available

in sufficient quantities to supply drinking water needs. 

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23227

Comment: 6. The location and proximity of other formations to USDWs may preclude their 

use for GS. EPA seeks comment on prohibiting injection into such formations if 

they are above the lowermost USDW. EPA Notice 43503. 

This arbitrary exclusion would eliminate a vast number of potential 

sequestration zones. Enhanced oil and gas recovery operations above the 

lowermost USDW have been taking place for a very long time. Exclusion of these 

zones where other abundant supplies of freshwater are available may 

unnecessarily limit sequestration options. These situations are best handled 

locally where all the pertinent regional geologic factors can be considered. 

The buoyancy of carbon dioxide suggests this in an unnecessary restriction since 

it would move injectate away from the USDWs below the sequestration zone. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation.

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please
see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23236

Other EPA Comment Codes and Descriptions: 3822 2.3.1.1 Depth of surface casing (seeking

comment) 

Comment: 16. EPA seeks comment on the proposed GS well requirements for depth of surface 

casing, the cementing of long-string casing, and construction with a packer set 

opposite a cemented interval. EPA Notice 43509. 

Requiring setting surface casing below the lowermost USDW would preclude 

injection above the lowermost USDW, which as earlier stated, would eliminate a 

vast number of potential sequestration zones. Enhanced recovery operations 

above the lowermost USDW have been taking place for a very long time. Exclusion 

of these zones where other abundant supplies of freshwater are available may 

unnecessarily limit sequestration options. These situations are best handled 

locally where the regional geologic factors can be considered. Setting the 

surface casing below the lowermost USDW may not be technically feasible. 

Response: EPA disagrees that the surface casing requirements in the GS rule preclude injection

below deep USDWs. The final GS rule at §146.86(b)(2) requires that surface casing extend through

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

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

accomplished, and it allows the owner or operator to propose alternate methods that provide a

sufficient amount of cement to meet the standard that USDWs are protected from endangerment.

EPA notes that there are many potential ways to meet the requirement, such as the use of staged

cementing.

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is

very deep. To further address comments on deep injection wells, the final GS rule at §146.95

includes requirements for owners or operators that seek a waiver of the injection depth requirements.

Owners or operators of wells operating under injection depth waivers must comply with additional

construction requirements to ensure that wells used to inject above or between USDWs are

protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.

EPA stresses that protection of USDWs from endangerment, regardless of their depth or the number

of USDWs in an area, is the primary mission and mandate of the UIC program and the purpose of

all requirements for injection wells. Any injection activity must be demonstrated to not endanger

USDWs, regardless of their depth, and if such non-endangerment cannot be shown, the activity will

not be allowed under UIC requirements or the SDWA.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23245

Other EPA Comment Codes and Descriptions: 4410 2.4.4.3.1 Comments in favor of allowing

injection above/between USDWs in certain circumstances 

Comment: 23. EPA is aware that the proposed requirement of injecting CO2 below the 
lowermost USDW may preclude injection into certain targeted geologic formations, 

which may be storage sites currently under consideration for GS. As a result, 

the Agency is considering and requesting comment on alternative approaches that 

would allow injection between and/or above the lowermost USDW, and thus 

potentially allow for more areas to be available for GS while preventing USDW 

endangerment. EPA Notice 43512. 

Injection into a formation above the lowermost USDW should be allowed. As 

commented earlier, if injection above the lowermost USDW is not allowed it would 

eliminate a vast number of potential sequestration zones. Enhanced recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are 

available may severely limit sequestration options. These situations are best 

handled locally where other regional geologic factors can be considered. 

Demonstration that the upper and lower confining zones are adequate to prevent 

migration should be sufficient. The fact that the carbon dioxide plume is 

buoyant will protect any deeper USDW. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

Additionally, the final GS rule does not categorically preclude or prohibit injection into any type of

formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach For

additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment., please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23246

Other EPA Comment Codes and Descriptions: 4410 2.4.4.3.1 Comments in favor of allowing

injection above/between USDWs in certain circumstances 

Comment: 24. EPA is soliciting comment on whether CO2 injection should be allowed into an 
injection zone above the lowermost USDW, when the Director determines that 

geologic conditions (e.g., thousands of feet of intervening formations between 

the injection zone and the overlying and/or underlying USDWs) exist that will 

prevent fluid movement into adjacent USDWs. EPA Notice 43512. 

Injection into a formation above the lowermost USDW should be allowed. As 

commented earlier, if injection above the lowermost USDW is not allowed it would 

eliminate a vast number of potential sequestration zones. Enhanced recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are 

available may severely limit sequestration options. These situations are best 

handled locally where other regional geologic factors can be considered. 

Demonstration that the upper and lower confining zones are adequate to prevent 

migration should be sufficient. The fact that the carbon dioxide plume is 

buoyant will protect any deeper USDW. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23276

Other EPA Comment Codes and Descriptions: 4410 2.4.4.3.1 Comments in favor of allowing

injection above/between USDWs in certain circumstances 

Comment: 144.6 Class VI wells are to be limited to injection beneath the lowermost 

formation containing a USDW. This arbitrary exclusion would eliminate a vast 

number of potential sequestration zones. Enhanced oil and gas recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are 

available may unnecessarily limit sequestration options. These situations are 

best handled locally where all the pertinent regional geologic factors can be 

considered. The buoyancy of carbon dioxide suggests this in an unnecessary 

restriction since it would move injectate away from the USDWs below the 

sequestration zone. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23278

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: 146.81(d) Geologic sequestration project should be redefined as follows: 

Geologic sequestration project means an injection well or wells used to emplace 
a carbon dioxide stream into an injection zone for geologic sequestration. 

Geologic sequestration projects should not be limited to beneath the lowermost 

formation containing a USDW. 

Response: EPA has not revised the definition of a geologic sequestration project for the final rule.

However, as described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs. 

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23287

Other EPA Comment Codes and Descriptions: 3822 2.3.1.1 Depth of surface casing (seeking

comment) 

Comment: 

146.86(b)2 Requiring setting surface casing below the lowermost USDW would 

preclude injection above the lowermost USDW, which as earlier stated, would 

eliminate a vast number of potential sequestration zones. Enhanced recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are 

available may unnecessarily limit sequestration options. These situations are 

best handled locally where the regional geologic factors can be considered. 

Setting the surface casing below the lowermost USDW may not be technically 

feasible. 

Response: EPA disagrees that the surface casing requirements in the GS rule preclude injection

below deep USDWs. The final GS rule at §146.86(b)(2) requires that surface casing extend through

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

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

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

a sufficient amount of cement to meet the standard that USDWs are protected from endangerment.

EPA notes that there are many potential ways to meet the requirement, such as the use of staged

cementing.

EPA adds that protection of USDWs is the primary mission and mandate of the UIC program and

the purpose of all requirements for injection wells. Any injection activity must be demonstrated to

not endanger USDWs, regardless of their depth, and if such a demonstration cannot be made, then

the activity will not be allowed under UIC requirements or the SDWA. 

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW is

very deep. To further address comments on deep injection wells, the final GS rule at §146.95

includes requirements for owners or operators that seek a waiver of the injection depth requirements.

Owners or operators of wells operating under injection depth waivers must comply with additional

construction requirements to ensure that wells used to inject above or between USDWs are

protective. See the discussion of the waiver approach in the preamble to the final GS rule for

additional information.
Commenter Name: Kurt Waltzer Letter ID: 0250

Commenter Organization: Clean Air Task Force Comment ID: 22297

Comment: The rule should not prohibit in a blanket fashion GS sites located above the 

lowermost USDW, but should permit such sites only under certain conditions that 

are not applicable to sites below the lowermost USDW 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Walter L. Baker Letter ID: 0253

Commenter Organization: Utah Division of Water Quality Comment ID: 22342

Comment: regulations for the rapid deployment of CCGS projects. We do not, however, 

support the limitation of carbon sequestration below the lowermost underground 

source of drinking water (USDW). The determination for siting a CCGS project 

should be based on assessment of site specific conditions including the presence 

of an adequate upper and lower confining zone to protect USDW both above and 

below the injection zone. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

It establishes: 1) requirements specifying information that owners or operators must submit, and

Directors must consider, in consultation with PWSS Directors; 2) procedures for public notice of a

waiver application and for Director-Regional Administrator communication; 3) the waiver issuance

process; and, 4) additional requirements that apply to owners or operators of Class VI wells granted

a waiver of the injection depth requirements to ensure USDW protection above and below the

injection zone. 
EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Walter L. Baker Letter ID: 0253

Commenter Organization: Utah Division of Water Quality Comment ID: 22352

Comment: REQUIREMENT OF INJECTION BELOW THE LOWERMOST USDW 

We do not support EPA's proposed categorical requirement of injection CO2 below 

the lowermost USDW. We feel this would restrict the areas in which CCGS could 

be deployed. If site- specific hydrogeologic conditions, well construction, and 

operating parameters can be shown to provide protection for all USDWs and other 

natural resources above and below the injection zone, the CCGS project should be 

allowed. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs. 

EPA believes that proper siting, monitoring, and containment capacity are critical elements of Class

VI injection for GS. However, the Agency also believes that injection into non-USDW formations

above and between USDWs presents unique challenges related to movement of CO2 in the

subsurface, which requires a unique approach to ensure that USDWs are protected. Therefore, the

Agency believes that additional requirements are appropriate and necessary for wells that would

inject into non-USDWs above and between USDWs.

Commenter Name: Mike Nasi Letter ID: 0254

Commenter Organization: Clean Coal Technology Foundation of Texas Comment ID: 22362

Other EPA Comment Codes and Descriptions: 1250 1.1.1.4 Flexibility is needed (performancebased standards) 

Comment: 1. Geologic Siting Section 1421(b)(3)(A) of the Safe Drinking Water Act mandates 

that the UIC regulations developed by EPA "permit or provide for consideration 

of varying geologic, hydrological, or historical conditions in different States 

and in different areas within a State." Limiting CO2 injection to geologic 

formations that lie below the lowermost USDW is inconsistent with Congress' 
mandate, and thus, CCTF believes that a blanket constraint that limits injection 

only to reservoirs below the USDW is inappropriate. A performance based approach 

that would place containment requirements on the acceptable reservoirs would be 

more sensible. Accordingly, we believe that the rule should allow a range of 

injection sites and methods provided that the ultimate performance based 

objective of protecting USDWs is achieved. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. 

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24845

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 144.80 

EPA Proposal: 11. Section 144.80 is amended by revising the first sentence in 

paragraph (e) and by adding paragraph (f)to read as follows: 

§ 144.80 What is a Class V injection well? * * * * * 

(e) Class V. Injection wells not included in Class I, II, III, IV or VI. * * 

* 

(f) Class VI. Wells used for geologic sequestration of carbon dioxide. 

GWPC Recommendations: (4) For enhanced recovery of oil or natural gas where 

geologic sequestration is occurring during or in connection with enhanced 

recovery of oil or natural gas provided (i) there is reasonable expectation of 

more than insignificant future production volumes or rates as a result of carbon 
dioxide injection and (ii) operating pressures are no higher than reasonably 

necessary to produce such volumes or rates; 

(f) Class VI. Wells injecting a carbon dioxide stream for geologic 

sequestration except those wells described in subsection (b)(4) of this section 

or otherwise excluded from this Class. 

Rationale: There should not be a blanket prohibition concerning injection above 

USDW’s or at specific levels. The determination of injection zones should be 

based upon appropriate containment. This is especially true in light of recent 

calls for changes in the definition of a USDW to include formations greater than 

10K PPM TDS and the fact that several states including Wyoming and California 

might be prevented from instituting geologic sequestration as a practical matter 

if injection were limited to above USDW’s due to the great depth of some USDW’s. 

This would create a situation where otherwise good injection zones are 

artificially excluded, thus decreasing the overall availability of geologic 

sequestration in the U.S. 

The GWPC also recommends EPA consider retaining all geologic sequestration in 

oil and gas reservoirs under the jurisdiction of Class II UIC programs and 

create a subclass within this program for geologic storage of carbon dioxide. 

This subclass (Class II GS) would be used for those wells that depart from the 

traditional uses of Class II wells for enhanced recovery, and result in the 

application of Class VI standards. This change would eliminate any confusion 

over whether a Class II CO2 injection well used for enhanced recovery might also 

need a Class VI permit and would avoid the need to change jurisdiction for a 

well from one state agency to another over time. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying

information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements

to ensure USDW protection above and below the injection zone. 

EPA adds that it has revised the definition of a Class VI well to read as follows: “Wells that are not

experimental in nature that are used for geologic sequestration of carbon dioxide beneath the

lowermost formation containing a USDW; or, wells used for geologic sequestration of carbon

dioxide that have been granted a waiver of the injection depth requirements pursuant to requirements

at §146.95 of this chapter; or, wells used for geologic sequestration of carbon dioxide that have

received an expansion to the areal extent of an existing Class II enhanced oil recovery or enhanced

gas recovery aquifer exemption pursuant to §§146.4 of this chapter and 144.7(d).”

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.
In response to the comment that GS wells should be regulated as Class II wells, EPA believes that

injection for the primary purpose of long term storage is sufficiently different from Class II ER

operations and warrants tailored requirements. For example, the volume of CO2 anticipated to be

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

conditions will also be different, with Class VI injection operations involving large volumes of CO2

and likely having higher pressures within their storage formations than Class II ER projects. The

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

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

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

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

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

allowing for site-specific flexibility. EPA is developing guidance on transitioning permits from Class

II to Class VI. The guidance will assist Directors in determining whether an injection project should

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

the primary purpose is long-term storage of large volumes of CO2. This guidance will be available

on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA also recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. However, EPA is not

changing the USDW definition; changing the definition of a USDW is outside the scope of the GS

rulemaking. The GS rule focuses on ensuring protection of USDWs, as required under the SDWA,

by establishing regulations to ensure the safe injection of CO2 for long-term storage.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24849

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.5 

EPA Proposal: 13. Section 146.5 is amended as follows: 

a. Revising the first sentence in paragraph (e) introductory text; and 

b. Adding paragraph (f). 

(f) Class VI. Wells used for geologic sequestration of carbon dioxide beneath 

the lowermost formation containing an underground source of drinking water 

(USDW). 

GWPC Recommendations: (4) For enhanced recovery of oil or natural gas where 

geologic sequestration is occurring during or in connection with enhanced 

recovery of oil or natural gas provided (i) there is reasonable expectation of 

more than insignificant future production volumes or rates as a result of carbon 

dioxide injection and (ii) operating pressures are no higher than reasonably 

necessary to produce such volumes or rates; 

(f) Class VI. Wells injecting a carbon dioxide stream for geologic 

sequestration except those wells described in subsection (b)(4) of this section 

or otherwise excluded from this Class. 
Rationale: There should not be a blanket prohibition concerning injection above 

USDW’s or at specific levels. The determination of injection zones should be 

based upon appropriate containment. This is especially true in light of recent 

calls for changes in the definition of a USDW to include formations greater than 

10K PPM TDS and the fact that several states including Wyoming and California 

might be prevented from instituting geologic sequestration as a practical matter 

if injection were limited to above USDW’s due to the great depth of some USDW’s. 

This would create a situation where otherwise good injection zones are 

artificially excluded, thus decreasing the overall availability of geologic 

sequestration in the U.S. 

The GWPC also recommends EPA consider retaining all geologic sequestration in 

oil and gas reservoirs under the jurisdiction of Class II UIC programs and 

create a subclass within this program for geologic storage of carbon dioxide. 

This subclass (Class II GS) would be used for those wells that depart from the 

traditional uses of Class II wells for enhanced recovery, and result in the 

application of Class VI standards. This change would eliminate any confusion 

over whether a Class II CO2 injection well used for enhanced recovery might also 

need a Class VI permit and would avoid the need to change jurisdiction for a 

well from one state agency to another over time. 

Response: Please see the response to the commenter’s suggested revision to §144.80.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24861

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: EPA Proposal: Geologic sequestration project means an injection well or wells 

used to emplace a carbon dioxide stream beneath the lowermost formation 

containing a USDW. It includes the subsurface three-dimensional extent of the 

carbon dioxide plume, associated pressure front, and displaced brine, as well as 

the surface area above that delineated region. 

GWPC Recommendations: Geologic sequestration project means an injection well or 

wells used to emplace a carbon dioxide stream into an injection zone for 

geologic sequestration. 

Rationale: Replace "beneath the lowermost formation containing a USDW "with 

"into an injection zone" 

Suggest moving the second sentence to the definition of AOR. 

Response: In the final rule, EPA revised the definition of a geologic sequestration project to account

for the new requirements to include “wells used for geologic sequestration of carbon dioxide that

have been granted a waiver of the injection depth requirements pursuant to requirements at

§146.95.”

Letter ID: 0263
Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22792

Comment: II. H. What Are the Target Geologic Formations for GS of CO2? 

G. As with unmineable coal seams, EPA seeks comment on prohibiting injection into 

such formations if they are above the lowermost USDW. 

IOGCC Response: There should be no blanket prohibition against injection into any 

approved geologic zone even if above the lowermost USDW. There maybe 

circumstances where this is perfectly appropriate and safe. The decision needs to be 

site-specific and based on evaluation of local geology. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Letter ID: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22809

Comment: III A. 4 Proposed Injection Well Operating Requirements 

X. As a result, the Agency is considering and requesting comment on alternative 

approaches that would allow injection between and/or above the lowermost USDW, 

and thus potentially allow for more areas to be available for GS while preventing 

USDW endangerment. 

IOGCC Response: There should be no blanket prohibition against injection into a 

zone even if above the lowermost USDW. There maybe circumstances where it is 

perfectly appropriate and safe. The decision needs to be site specific based on 

local geologic conditions. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95
establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs. Additionally,

the final GS rule does not categorically preclude or prohibit injection into any type of formation.

Letter ID: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22810

Comment: III A. 4 Proposed Injection Well Operating Requirements 

Y. In summary, EPA is soliciting comment on whether CO2 injection should be 

allowed into an injection zone above the lowermost USDW, when the Director 

determines that geologic conditions (e.g., thousands of feet of intervening 

formations between the injection zone and the overlying and/or underlying USDWs) 

exist that will prevent fluid movement into adjacent USDWs. 

IOGCC Response: Injection criteria on which zones to use should be site specific 

based on local geologic conditions. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs. Additionally,

the final GS rule does not categorically preclude or prohibit injection into any type of formation.

Commenter Name: Steven Chester Letter ID: 0264

Commenter Organization: Michigan Department of Environmental Quality

(MDEQ)

Comment ID:

22839

Comment: EPA (III . A. 4.) proposes allowing injection for sequestration above the 

lowermost USDW (Underground Source of Drinking Water). 

- Staff believes injection should be allowed when the EPA Director 

determines that geologic conditions exist that will prevent fluid movement into 

adjacent USDWs. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to
concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Michael Moore Letter ID: 0265

Commenter Organization: North American Carbon Capture & Storage

Association (NACCSA)

Comment ID:

22851

Comment: - Siting/Secondary Containment: Injection above the lowermost USDW should 

not be categorically prohibited; further, any discretion vested in the UIC 

program director to require secondary containment should be explicitly bounded 

with appropriate criteria for its exercise. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

The final rule establishes: 1) requirements specifying information that owners or operators must

submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for public

notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class

VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. The final rule also establishes limited circumstances under which

expansions of the areal extent of aquifer exemptions may be granted for owners or operators of

Class II EOR/EGR wells transitioning to Class VI injection for GS. 

For additional information on the waiver approach and aquifer exemptions for Class VI wells, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Michael Moore Letter ID: 0265

Commenter Organization: North American Carbon Capture & Storage

Association (NACCSA)

Comment ID:

22861

Comment: 1. Ban on Injection Above the Lowermost USDW 

The proposed regulations do not permit project operators to inject and store CO2 

above the lowermost formation containing a USDW. NACCSA believes that a 

categorical elimination of receiving formations is unnecessary and undesirable. 

Rather, the appropriateness of any given receiving formation-as with the bulk of 

issues related to the siting of projects-should be considered on a case-by-case 

basis in light of the geologic characteristics of a given project and based on 

the application of clear and appropriate parameters set forth in the rules. 

Categorically eliminating a set of potential receiving formations is simply 
unnecessary in light of the overall function of the UIC rules. As a general 

proposition, permit applicants must demonstrate that projects will not endanger 

USDWs; permit applicants for CO2 injection and storage projects would be held to 

the same standard. The proposed rules would require permit applicants to 

demonstrate that the project will be sited in areas with a "suitable geologic 

system," consisting of an injection zone of sufficient areal extent, thickness, 

porosity, and permeability to receive the total anticipated volume of injectate, 

as well as a confining zone free of transmissible faults or fractures and 

sufficient to contain the injected stream and any displaced fluids, considering 

the proposed maximum pressures and volumes of injection, without fracturing. It is 

NACCSA's view that if the "suitable geologic system" contains confining zones 

above and below the injection formation that will not allow the endangerment 

of USDWs,injection above a USDWshould be allowed because the system will still meet 

the groundwater protection requirements of the UIC program. The fact that permit 

applications would be considered based on site specific information would 

mean that the regulator could evaluate whether individual projects would be 

protective of groundwater regardless of their depth with respect to USDWs. 

Further, a blanket exclusion will hinder the ability of existing and possibly 

future Class I, II, and V projects to convert to Class VI projects, as the 

proposed grandfathering requirement is limited to well construction (as further 

discussed below), thus excluding projects that do not inject below the lowermost 

USDW from the scope of potential grandfathering. Existing (and future) projects 

that do not inject beneath the lowermost USDW would seemingly be stranded, left 

with no ability to convert to Class VI GS projects. Such a risk greatly 

disincentivizes many projects that would otherwise be likely to go forward 

and would hamper commercialization of CCS. And creation of such a disincentive is 

unnecessary because the wells at issue would have been designed and constructed 

pecifically with injection of CO2 and the protection of USDWs in mind. 

While NACCSA acknowledges that EPA has raised for consideration the possibility 

of aquifer exemptions or the use of discretion to allow injection above the 

lowermost USDW in a given case, NACCSA submits that such a procedure would 

introduce increased complexity to the process with no corresponding increase in 

protection afforded to USDWs as compared to an approach under which no default 

limitations on siting exist and the merits of a proposed receiving formation are 

considered in the context of a particular project, using clearly identified and 

appropriate factors. And in the context of existing or proposed projects that may be 

seeking to later convert to Class VI wells, such provisions would create 

unnecessary uncertainty regarding the potential viability of projects going 

forward. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to
UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs.

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Michael Moore Letter ID: 0265

Commenter Organization: North American Carbon Capture & Storage

Association (NACCSA)

Comment ID:

22862

Comment: Finally, a default limitation on injections to only those formations below the 

lowermost USDW- currently in place only for Class I hazardous waste injection 

wells-is likely to create a public misimpression that CO2 injection wells are 

analogous to hazardous waste injection wells and carry analogous risks. 

NACCSA urges EPA to consider the potential effects of each proposed regulation on 

public perception of CCS, as attaching unnecessary stigmas to CCS will do nothing 

to further its development or to protect USDWs. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The waiver approach requires the

submission of extensive, site-specific information (in conjunction with the permit application

submission) to demonstrate that injection of CO2 into a non-USDW that is above or between

USDWs can be done in a manner that is protective of USDWs. The requirements are designed to

ensure that the owner or operator, the Director, and the Regional Administrator consider, on a site

specific basis, the implications, benefits, and challenges associated with GS and ensuring water

availability and USDW protection. EPA believes that the additional procedures for public notice of a

waiver application and for Director-Regional Administrator communication at §146.95 will improve

public confidence in and acceptance of GS projects operating under injection depth waivers. EPA

clarifies that, due to the unique nature of the injection depth waiver process and in an effort to ensure

national consistency and application of the requirements, the requirement at §146.95(d) indicates that

the Regional Administrator makes the final determination regarding waiver issuance following an

evaluation of all site-specific information, public notice, and recommendations from the UIC

Director. 

EPA disagrees that the GS regulation overstates the risk of CO2 injection. EPA recognizes that

injecting large volumes of CO2 for GS poses unique challenges that, if not properly managed, could

endanger drinking water sources and have other adverse impacts. However, with proper site

selection, the final, tailored, Class VI requirements address the large volumes of CO2 injected, its

buoyancy, potential corrosivity in the presence of water, and potential impurities in the CO2 stream.
In addition, the tailored permitting, siting, construction, operation, monitoring, and post-injection site

care requirements in the GS rule are intended to prevent leakage from injection formations and

protect USDWs.

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Michele Schoepper Letter ID: 0503

Commenter Organization: American Petroleum Institute Comment ID: 21173

Comment: The first being the restriction of injections to formations below the lowermost 

underground source of drinking water. This requirement is not necessary for the 

protection of the USDWs and would remove a vast number of viable formations from 

consideration. 

Industry has shown that it can operate CO2 injection wells in the EOR context 

without endangering with USDWs that are located below the injection zone. An 

excellent example is the Salt Creek EOR Project in Wyoming, which has a USDW 

below the injection zone. 

Moreover, under the proposed rule there are other measures that would provide 

real assurance of formation integrity and require operators to demonstrate that 

their project will not endanger USDWs, making the injection below the lowermost 

USDW restriction unnecessary. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

While the Agency acknowledges the experience gained by the oil and gas industry and other

injection activities, EPA identified unique challenges posed by large-scale GS including large

injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the

potential presence of impurities in captured CO2, and its mobility within subsurface geologic

formations that warrant the tailored approach in the GS rule. Furthermore, the Agency believes that
wells that inject into non-USDW formations above and between USDWs presents additional

challenges that warrant additional requirements.

Commenter Name: Brian Williams Letter ID: 0507

Commenter Organization: BP Alternative Energy Comment ID: 21166

Comment: With regards to well operations for the next phase, comments about no CO2 

injection above the lowermost USDW. The EPA does not subscribe to a blanket 

constraint that would limit injections only to reservoirs below the USDW. 

More appropriate given the EPA's general performance based approach, which we 

applaud, would be to place containment requirements on the acceptable 

reservoirs. As long as CO2 can be injected and stored securely with minimal 

chance of breaching containment, either via the well bore or via geological 

features, proximity to USDW, whether shallow or deeper, should not matter. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Scott Anderson Letter ID: 0520

Commenter Organization: Environmental Defense Fund Comment ID: 21423

Comment: A couple comments on some issues that we still have under review, but I can at 

least go this far at this time. We would urge the EPA to give serious 

consideration to the points that many have made about not restricting this rule 

to sites that are below the lowest USDW. And we would also urge the EPA to give 

Response: EPA agrees that protecting USDWs from endangerment must be a top priority. The

Agency believes that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. It establishes: 1) requirements specifying information that owners or operators must

submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for public

notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class

VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. 

EPA believes that the requirements at §146.95 will ensure USDW protection while providing
flexibility to UIC Program Directors and owners or operators who undertake CO2 injection for GS.

The Agency believes this approach: 1) responds to concerns about local and regional geologic

storage capacity limitations imposed by the proposed injection depth requirements; 2) allows for a

more site-specific assessment of injection depth for GS projects; 3) accommodates injection into

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or

between USDWs when appropriate and where it can be demonstrated that USDWs will be protected;

and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to

addressing injection depth variability through a waiver process responds to concerns about future

drinking water resource availability and the need to ensure that high quality water remains available

in sufficient quantities to supply drinking water needs. For additional information on the waiver

approach, please see the final rule and preamble, as well as EPA's responses to comments on the

Notice of Data Availability and Request for Comment.

Commenter Name: Steve Crookshank Letter ID: 0523

Commenter Organization: American Petroleum Institute (API) Comment ID: 21356

Comment: should be reconsidered for further improvement. The first of these is the 

proposal to restrict injection into formations below the lower most underground 

source of drinking water or USDW. This requirement is not necessary for 

protection of USDW's and would remove a vast number of viable formations from 

consideration. Industry has shown they can operate CO2 injection wells and EOR 

context without endangering USDW's that are located below the injection zone. An 

excellent example is the Saw Creek EOR project in Wyoming which has a USDW 

directly below the injection zone. 

Moreover, under the proposed rule, there are other measures that provide real 

assurance of formation integrity and require operators to demonstrate that the 

project will not endanger USDW's making the lower most USDW restriction 

unnecessary. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying

information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements

to ensure USDW protection above and below the injection zone. 

While the Agency acknowledges the experience gained by the oil and gas industry and other

injection activities, EPA identified unique challenges posed by large-scale GS including large

injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the

potential presence of impurities in captured CO2, and its mobility within subsurface geologic

formations that warrant the tailored approach in the GS rule. Furthermore, the Agency believes that

wells that inject into non-USDW formations above and between USDWs presents additional

challenges that warrant additional requirements. 

For additional information on the waiver approach, please see the final rule and preamble, as well as
EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Kevin Frederick Letter ID: 0525

Commenter Organization: Wyoming Department of Environmental Quality Comment ID: 21402

Other EPA Comment Codes and Descriptions: 4410 2.4.4.3.1 Comments in favor of allowing

injection above/between USDWs in certain circumstances 

Comment: There are a few areas which we do not agree with EPA's proposed approach. 

Especially prohibiting injection into formations if they are above the lower 

most USDW. We believe it is imperative that the director be allowed discretion 

to allow injection above or between USDW's in specific geologic settings where 

the depth of the USDW's preclude geologic sequestration, make GS technically 

challenging or significantly limits storage capacity. Such approval by the 

director would allow injection between USDW's and thereby allow injection above 

the lower most USDW. In most circumstances it may be demonstrated that the 

USDW's would not be in danger. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Cynthia Lane Letter ID: 0528

Commenter Organization: American Water Works Association (AWWA) Comment ID: 21382

Comment: measures in the proposed rule. We also support the portion of the rule that 

prohibits injection of carbon dioxide above the lower most USDW. 

Response: EPA agrees that protecting USDWs from endangerment must be a top priority. The

Agency believes that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific
information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. It establishes: 1) requirements specifying information that owners or operators must

submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for public

notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class

VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. 

EPA believes that the requirements at §146.95 will ensure USDW protection while providing

flexibility to UIC Program Directors and owners or operators who undertake CO2 injection for GS.

The Agency believes this approach: 1) responds to concerns about local and regional geologic

storage capacity limitations imposed by the proposed injection depth requirements; 2) allows for a

more site-specific assessment of injection depth for GS projects; 3) accommodates injection into

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or

between USDWs when appropriate and where it can be demonstrated that USDWs will be protected;

and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to

addressing injection depth variability through a waiver process responds to concerns about future

drinking water resource availability and the need to ensure that high quality water remains available

in sufficient quantities to supply drinking water needs. For additional information on the waiver

approach, please see the final rule and preamble, as well as EPA's responses to comments on the

Notice of Data Availability and Request for Comment.

Commenter Name: Cynthia Lane Letter ID: 0528

Commenter Organization: American Water Works Association (AWWA) Comment ID: 21383

Other EPA Comment Codes and Descriptions: 1610 1.3.1 Risks to USDWs 

Comment: As the demand for water increases during the upcoming century and changes in 

climate impact traditional water supplies, water utilities will look for new 

sources of drinking water. It is likely that as a result of these changes, there 

will be a greater reliance on ground water for both new supplies and conjunctive 

use. The possibility exists that utilities might want to use some of these 

injection site aquifers as new potable sources. In fact, in several communities 

across the country, brackish waters that are previously considered to be 

unusable because they are above ten thousand TDS are now being used as drinking 

water sources. 

As desalination technology advances, the brackish water sources are treated to 

EPA drinking water standards and provided to water utility customers. As this 

technology improves, even more saline water may be used in the future therefore 

AWWA suggest that the selection standards for potential injection aquifers and 

for USDW's be reviewed and revised to prevent contamination of aquifers that may 

be considered viable sources of drinking water in the near future. 

Response: The Agency acknowledges the commenter’s concerns about water resources and future

water resource availability. However, modifying the definition of a USDW is outside the scope of

the GS rulemaking. USDWs are defined as aquifers currently being used as sources of drinking

water or those capable of supplying a public water system, with a total dissolved solids (TDS)

content of 10,000 milligrams per liter or less as specified in §144.3. 
The primary goal of the UIC Program under the SDWA is to protect USDWs from endangerment in

order to ensure a reliable supply of drinking water for the American public. The GS rule, as part of

the UIC program regulations, continues the program’s tradition of ensuring the protection of

USDWs. EPA expects that the tailored permitting, siting, construction, operation, monitoring, and

post-injection site care requirements in the GS rule will prevent leakage from injection formations

and protect USDWs.

As described above, EPA agrees that protecting USDWs from endangerment must be a top priority.

The Agency believes that there are limited circumstances where injection above the lowermost

USDW can be performed in a manner that protects USDWs, as long as appropriate protections are in

place. The final GS rule at §146.95 establishes a process by which owners or operators can seek a

waiver of the Class VI injection depth requirements for injection into non-USDW formations above

and/or between USDWs.

Commenter Name: Mike Moore Letter ID: 0532

Commenter Organization: North American Carbon Capture and Storage

Association (NACCSA)

Comment ID:

21366

Comment: Our first area of concern relates to EPA's proposed limitations on receiving 

formations. It permits injections only beneath the lower most formation 

containing a USDW. This limitation will hamper deployment of CCS by excluding 

many sites otherwise suitable for CCS. Such a blanket limitation is unnecessary 

because operators will be required to show that projects will not endanger 

drinking water sources. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the rule does not categorically

preclude or prohibit injection into any type of formation.

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: George Peridas Letter ID: 0534

Commenter Organization: Natural Resources Defense Council (NRDC) Comment ID: 21457

Other EPA Comment Codes and Descriptions: 4410 2.4.4.3.1 Comments in favor of allowing
injection above/between USDWs in certain circumstances 

Comment: Now on the technical issues, the ones I would like to mention briefly without 

going into detail; I will defer to the comments about, is the definition of the 

area of review. The definition and treatment of a fault in the subsurface, I 

think I will echo some previous comments on whether to inject above or below the 

lowest USDW. The definition of a USDW might change. The TDS level in the future 

and that is crucial to policy decisions, but we will have to think very 

carefully of, but I think there are good examples of safe CO2 injection that are 

above the lowest USDW. I am willing to make sure that the emphasis is on having 

the adequate confinement systems and confining layers that protect USDW's 

whether they are above or below. 

Response: EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. Specifically, the Director must consider whether alternative

injection sites are available; community needs, demands, and supply from drinking water resources;

planned needs, potential and/or future use of USDWs and non-USDWs in the area; and a plan for

securing alternative resources or treating USDW formation waters in the event of contamination

related to the Class VI injection activity.

EPA is not changing the USDW definition; changing the definition of a USDW is outside the scope

of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as required under the

SDWA, by establishing regulations to ensure the safe injection of CO2 for long-term storage. 

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Comment Code: 4340 2.4.4.2 Minimum injection depth (seeking comment) 

Individual Comments

Commenter Name: Carl Carlsson Letter ID: 0131

Commenter Organization: SUEZ Energy Generation NA, LLC Comment ID: 21532

Comment: Minimum Injection Depths 

EPA is not prescribing a minimum injection depth to keep CO2 in a supercritical 

state since some operators may inject CO2 in a gaseous state, but describes the 

potential deleterious effects of a change in state (for supercritical CO2) and the 

expansion of gaseous CO2. SEGNA believes it would be reasonable to stipulate 

a minimum injection / storage depth for supercritical CO2, but allow a 

discretionary lower depth for injection of gaseous CO2. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects or

require that the CO2 be injected in a supercritical state. EPA believes that a determination of sitesuitability for GS (i.e., that subsurface formations will receive and confine injected CO2) should be

made on a site-specific basis. The GS rule, at §146.82, requires the owner or operator to provide
extensive site- and project-specific information to the Director to demonstrate that the site meets the

minimum site criteria at §146.83, that the CO2 will be contained within the injection formation, and

that USDWs will be protected from endangerment. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Christopher Murray Letter ID: 0207

Commenter Organization: Pacific Northwest National Laboratory Comment ID: 22448

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW; 4430 2.4.4.3.3 Injection into coal seams above USDWs

(seeking comment) 

Comment: Stratigraphic Restriction of Saline and Other Reservoirs to Below Lowermost USDW 

PROPOSED REGULATION FOR SALINE FORMATIONS 

p. 43494, c. 2 Saline formations: Deep and geographically extensive sedimentary 

rock layers saturated with waters or brines that have a high total dissolved 

solids (TDS) content (i.e., >10,000 mg/L TDS). 

p. 43505, c. 1 1. Proposed Geologic Siting Requirements Existing UIC 

requirements for siting injection wells include identification of geologic 

formations suitable to receive the injected fluids and confine them such that 

they are isolated below the lowermost USDWs, minimizing the potential for 

endangerment. 

p. 43502-43503, section Hon target geologic formations As with unmineable coal 

seams, EPA seeks comment on prohibiting injection into such formations [basalts, 

salt domes, and shales] if they are above the lowermost USDW. 

The EPA is soliciting comments on these issues: 

1. Whether CO2 injection should be allowed into an injection zone (saline 

sedimentary formations, unminable coal seam, basalt, salt caverns, shales, or 

other reservoirs) above the lowermost USDW, when the Director determines that 

geologic conditions exist that will prevent fluid movement into adjacent USDWs. 

2. Whether a designated USDW should be exempted to allow for GS, and under what 

conditions should these exemptions be approved. 
3. Whether all USDWs should be exempted below a CO2 injection receiving bed. 

4. Whether the EPA should set a minimum injection depth requirement for GS, 

rather than require that such injection take place below the lowermost USDW. 

DISCUSSION 

Three of the most important issues here are (a) the physical location of saline 

formations or other types of geologic reservoirs for GS, relative to USDWs; (b) 

under what circumstances the EPA should remove one or more water-bearing zones 

from the list of USDWs to allow injection; and (c) under what other conditions 

should the EPA allow injection above a USDW. 

In addition to injection into saline formations, EPA recognizes that basalt, 

unmineable coal seams, salt domes, abandoned mines, black shales and other types 

of reservoirs may be promising emerging targets. Basalts, in particular appear 

to have considerable potential for GS Research by PNNL and others indicates that 

extruded basalt flow tops and flow bases may have considerable potential for GS. 

Research by PNNL and others indicates that extruded basalt flow tops and flow 

bases may have regional, multi-gigaton capacity for CO2 storage. In addition, 

laboratory experiments suggest that regional, multi-gigaton capacity for CO2 

storage. mineralization of large volumes of CO2 may proceed within a few years 

of injection (McGrail et al, 2006). 

In the proposed rule, the new Class VI wells would be allowed to inject CO2 into 

basalts, deep saline reservoirs, and other potential reservoirs only when they 

are beneath the lowermost USDW. 

A USDW is defined by the EPA as "An aquifer or portion of an aquifer that 

supplies any public water system or that contains a sufficient quantity of 

ground water to supply a public water system, and currently supplies drinking 

water for human consumption, or that contains fewer than 10,000 mg/1 total 

dissolved solids and is not an exempted aquifer." This definition would include 

many non-potable aquifers that would be candidates for GS. 

The EPA's reliance on the standard definition of a USDW as being solely <10,000 

mg/L TDS is far too restrictive. In many states, this standard is not applied - 

all groundwaters are protected regardless of water quality. In at least one 

state GS operations would be permitted if removing anthropogenic CO2 is 

considered a greater public benefit than the loss of a marginal aquifer. 

The EPA is aware that restricting GS to a position below all EPA defined USDWs 

would severely limit GS in many areas. Under the current proposed rule, directors 

may grant injection into deep, marginal USDWs that directly overlie crystalline 

basement rock and/or unmineable coal seams. In addition to these exceptions, the 

EPA would consider allowing operation of GS wells where receiving formations are 

above the lowermost USDW only where there are thousands of feet between the 

injection zone and the overlying and underlying USDWs. 

REFERENCES 
McGrail, B. P., H. T. Schaef, A. M. Ho, Y. Chien, J. J. Dooley, and C. L. 

Davidson. 2006. Potential for Carbon Dioxide Sequestration in Flood Basalts, J. 

Geophys. Res. 111, B12201. 

Response: Regarding injection into basalts, coal seams, and salt domes, EPA clarifies that the GS

rule does not categorically preclude injection of CO2 into any non-USDW formation types. The

purpose of the GS rule is to ensure protection of USDWs from endangerment, and the rule requires

that owners or operators demonstrate that wells are sited in suitable systems with geologic

formations to receive and confine injected CO2, as required at §146.83 of the GS rule. The Class VI

siting, well construction and operation, monitoring and testing, and post-injection site care and site

closure requirements are designed to ensure that injected CO2 remains within the target formation. If

an owner or operator can demonstrate to the Director's satisfaction that GS in coal seams, basalts,

salt domes, or shales can be accomplished in a manner that protects USDWs and meets all of the

requirements of the GS rule, the project may be permitted as a Class VI well. 

EPA acknowledges that there may be unknown risks associated with GS, particularly regarding GS

into formations such as coal seams, basalts, and salt domes, which have been the subject of limited

experimental projects in the past. EPA anticipates that in the short-term, GS into these types of

formations will continue to be experimental (i.e., if they are to test GS technologies and collect data),

and will likely be permitted as Class V experimental technology wells and be subject to UIC

Program Guidance #83. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs. The final GS rule at §146.95 establishes a

process by which owners or operators can seek a waiver of the Class VI injection depth

requirements. The waiver approach requires the submission of extensive, site-specific information

(in conjunction with the permit application submittal) to demonstrate that injection of CO2 into a

formation that is above or between USDWs can be done in a manner that is protective of USDWs.

The requirements are designed to ensure the owner or operator, the Director, and the Regional

Administrator consider, on a site specific basis, the implications, benefits, and challenges associated

with GS and ensuring water availability and USDW protection.

EPA is not changing the USDW definition; changing the definition of a USDW is outside the scope

of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as required under the

SDWA, by establishing regulations to ensure the safe injection of CO2 for long-term storage. 

EPA believes that there is increasing demand for water resources and that technology improvements

may make high TDS aquifers viable drinking water sources. EPA believes these potential resources

should be considered when injection depth waivers are sought. Therefore, the final GS rule at

§146.95(b) requires the Director to consider these issues in determining whether an injection depth

waiver is appropriate. Specifically, the Director must consider whether alternative injection sites are

available; community needs, demands, and supply from drinking water resources; planned needs,

potential and/or future use of USDWs and non-USDWs in the area; and a plan for securing

alternative resources or treating USDW formation waters in the event of contamination related to the
Class VI injection activity.

Comment Code: 4342 2.4.4.2.1 Comments in favor of setting a minimum injection depth 

Individual Comments

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23682

Comment: EPA Request for Comment: EPA seeks comment on whether the Agency should set a 

minimum injection depth requirement for CO2 GS, rather than require that such 

injection take place below the lowermost USDW. EPA Notice 43512. 

AWWA Response: EPA should consider setting a minimum injection depth for 

geologic carbon sequestration as well as requiring that the injection take place 

below either the lowermost USDW or the lowermost aquifer that would be used as a 

drinking water source. AWWA believes this is necessary to ensure that carbon 

dioxide injected in the supercritical phase remains as such. The IPCC Special 

Report on Carbon Dioxide Capture and Storage suggested that carbon dioxide 

should be sequestered depths of at least 800 to 1,000 meters because at these 

depths, supercritical carbon dioxide has a liquid-like density that provides the 

potential for efficient utilization of underground storage space in the pores of 

sedimentary rocks. Providing for a minimum depth for carbon dioxide injection 

would strengthen the protective measures for USDWs. However, it is important to 

note that the minimum injection depth should be coupled with the provision that 

carbon dioxide must be injected below either the lowermost USDW or the lowermost 

aquifer that could be used as a drinking water source. 

Response: EPA disagrees that it is necessary to set a minimum injection depth for GS projects and

the Agency believes that a determination of site-suitability for GS (i.e., that subsurface formations

will receive and confine injected CO2) should be made on a site-specific basis. The GS rule, at

§146.82, requires the owner or operator to provide extensive site- and project-specific information to

the Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2

will be contained within the injection formation, and that USDWs will be protected from

endangerment.

EPA agrees that protecting USDWs from endangerment must be a top priority. The Agency believes

that there are limited circumstances where injection above the lowermost USDW can be performed

in a manner that protects USDWs, as long as appropriate protections are in place. The final GS rule

at §146.95 establishes a process by which owners or operators can seek a waiver of the Class VI

injection depth requirements for injection into non-USDW formations above and/or between

USDWs. The waiver approach requires the submission of extensive, site-specific information (in

conjunction with the permit application submission) to demonstrate that injection of CO2 into a nonUSDW that is above or between USDWs can be done in a manner that is protective of USDWs. It

establishes: 1) requirements specifying information that owners or operators must submit, and

Directors must consider, in consultation with PWSS Directors; 2) procedures for public notice of a

waiver application and for Director-Regional Administrator communication; 3) the waiver issuance
process; and, 4) additional requirements that apply to owners or operators of Class VI wells granted

a waiver of the injection depth requirements to ensure USDW protection above and below the

injection zone.

Commenter Name: Steven Chester Letter ID: 0264

Commenter Organization: Michigan Department of Environmental Quality

(MDEQ)

Comment ID:

22840

Comment: EPA (III . A. 4.) proposes establishing a minimum injection depth rather than 

requiring injection below the lowermost USDW. 

- Staff believes minimum injection depths may be appropriate if sufficient 

information is available regarding the depths of wells that may have been drilled 

into an AoR prior to state or federal regulation. 

Response: EPA disagrees that it is necessary to set a minimum injection depth for GS projects and

the Agency believes that a determination of site-suitability for GS (i.e., that subsurface formations

will receive and confine injected CO2) should be made on a site-specific basis. The GS rule, at

§146.82, requires the owner or operator to provide extensive site- and project-specific information to

the Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2

will be contained within the injection formation, and that USDWs will be protected from

endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Comment Code: 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth 

Individual Comments

Commenter Name: Brian Williams Letter ID: 0116

Commenter Organization: BP Alternative Energy Comment ID: 22054

Comment: Minimum Injection depth vs. requirement to inject below lowermost USDW - BP 

disagrees with universal mandates for establishing minimum depths for CO2 

injection, as these should be site-specific based on the containment and 

capacity parameters of the storage site. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects
and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Steven Pirner Letter ID: 0153

Commenter Organization: South Dakota Department of Environment and

Natural Resources

Comment ID:

22138

Comment: 3. We would also recommend that a minimum injection depth for CO2 sequestration 

not be required, again to allow states more flexibility in determining areas 

where the process can occur. We believe the initial site evaluation, testing, 

modeling and so forth required of the owner/operators of a geologic 

sequestration site along with all operational testing would maintain protection 

of a USDW without requiring a prescriptive depth limitation. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site-specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.
Commenter Name: James Dooley Letter ID: 0156

Commenter Organization: Joint Global Change Research Institute, Pacific

Northwest National Laboratory

Comment ID:

22633

Comment: No Minimum Injection Depth Specified 

Page 43511. It is difficult to envision that there will be widescale deployment 

of CCS that would utilize formations that are shallow enough to favor injection 

of CO2 as a gas and not as supercritical fluid. It seems that a better way to 

approach this from a regulatory standpoint would be to require injection at 

depth that would call for injection as a supercritical fluid but to allow the 

Director to waive that requirement for cause and that the waiver would be 

contingent on the Class VI permitee satisfying additional requirements designed 

to ensure that the overarching goals of the SDWA and other environmental 

policies are fulfilled. 

It seems odd and inconsistent to not specify a minimum depth when CO2 is being 

injected into a water bearing formation that is below the lower most USDW, but 

EPA is proposing that there would need to be "thousands of feet between the 

injection zone and [BOTH] the overlying and underlying USDWs." (p. 43512). The 

overarching goal of the Class VI rule making is to protect USDWs and human 

health and welfare. If CO2 is buoyant and there are concerns about it migrating 

out of the target injection zone, it doesn’t seem consistent to specify a 

minimum depth in one relatively small subset of potential GS applications 

(injection of CO2 into a formation above the lowermost USDW) but not define a 

minimum depth for the vast majority of GS applications (injection of CO2 below 

the lower most USDW). 

Lastly, perhaps "depth" is too narrow of a concept of what is being discussed 

here. "Deeper than any USDW and not in communication (i.e., not connected 

hydrodynamically or via faults or other intrusions) with any USDW" or "Deeper 

than any USDW and geochemically and geomechanically isolated under current and 

modeled co- and post-injection conditions with any USDW" seems much closer to 

the mark in terms of protecting what society wants protected. 

Response: EPA disagrees that it is appropriate to set a minimum injection depth for GS projects and

the Agency believes that a determination of site-suitability for GS (i.e., that subsurface formations

will receive and confine injected CO2) should be made on a site-specific basis. The GS rule, at

§146.82, requires the owner or operator to provide extensive site- and project-specific information to

the Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2

will be contained within the injection formation, and that USDWs will be protected from

endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective
of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: James Childress Letter ID: 0158

Commenter Organization: Gasification Technologies Council (GTC) Comment ID: 23784

Comment: EPA seeks comment on whether the Agency should set a minimum injection depth 

requirement for CO2 GS, rather than require that such injection take place below 

the lowermost USDW. EPA Notice 93. 

EPA should neither require injection below the lowermost USDW nor alternately 

require a minimum depth requirement as geologic structures are likely to be 

encountered that provide for secure and safe storage. Examples of such storage 

that should be acceptable are domes and caverns. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24241

Comment: Rule Provisions: 73 FR 43512 

EPA Preamble Question: 26. EPA seeks comment on whether the Agency should set a 

minimum injection depth requirement for CO2 GS, rather than require that such 

injection take place below the lowermost USDW. EPA Notice 43512. 

API Response: There should be no minimum depth for injection of CO2. The primary 

consideration should be protection of USDWs. A requirement for a minimum depth 

suggests an intention by EPA to require injection of CO2 in a supercritical 
phase. Such a requirement is not appropriate since there may be areas where 

injection of CO2 in other phases may be the only option. Again, site-specific 

evaluation and protection of USDWs should be the basis for determining depth of 

injection. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects or

require that the CO2 be injected in a supercritical state. EPA believes that a determination of sitesuitability for GS (i.e., that subsurface formations will receive and confine injected CO2) should be

made on a site-specific basis. The GS rule, at §146.82, requires the owner or operator to provide

extensive site- and project-specific information to the Director to demonstrate that the site meets the

minimum site criteria at §146.83, that the CO2 will be contained within the injection formation, and

that USDWs will be protected from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Kenneth Nemeth Letter ID: 0176

Commenter Organization: Southern States Energy Board Comment ID: 23538

Other EPA Comment Codes and Descriptions: 2100 1.6 Target Geologic Formations for GS 

Comment: to USDWs). Equally important, there should not be limitations on formations that 

could be used for GS nor any depth limitations on injection zones. SSEB does not 

Response: EPA clarifies that the GS rule does not categorically preclude injection of CO2 into any

non-USDW formation types. The purpose of the GS rule is to ensure protection of USDWs from

endangerment, and the rule requires that owners or operators demonstrate that wells are sited in

suitable systems with geologic formations to receive and confine injected CO2, required at §146.83

of the GS rule. The Class VI siting, well construction and operation, monitoring and testing, and

post-injection site care and site closure requirements are designed to ensure that injected CO2

remains within the target formation. If an owner or operator can demonstrate to the Director's

satisfaction that GS in coal seams, basalts, salt domes, or shales can be accomplished in a manner

that protects USDWs and meets all of the requirements of the GS rule, the project may be permitted

as a Class VI well. 

EPA agrees that it is not appropriate to set a minimum injection depth for GS projects. EPA believes

that a determination of site-suitability for GS (i.e., that subsurface formations will receive and

confine injected CO2) should be made on a site-specific basis. The GS rule, at §146.82, requires the

owner or operator to provide extensive site- and project-specific information to the Director to

demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be contained

within the injection formation, and that USDWs will be protected from endangerment. 
EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23858

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW 

Comment: Geologic sequestration of CO2 need not be, in every instance, beneath the 

lowermost USDWs, nor should EPA set a minimum injection depth requirement. Such 

requirements likely would preclude injection into certain targeted geologic 

formations, which may include storage sites currently under consideration for 

GS. These formations may include unmineable coal seams, zones in between or 

above USDWs, and others. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects.

EPA believes that a determination of site-suitability for GS (i.e., that subsurface formations will

receive and confine injected CO2) should be made on a site-specific basis. The GS rule, at §146.82,

requires the owner or operator to provide extensive site- and project-specific information to the

Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be

contained within the injection formation, and that USDWs will be protected from endangerment. 

EPA believes that proper siting, monitoring, and containment capacity are critical elements of Class

VI injection for GS. However, the Agency also believes that injection into non-USDW formations

above and between USDWs presents unique challenges related to movement of CO2 in the

subsurface, which requires a unique approach to ensure that USDWs are protected. Therefore, the

Agency believes that additional requirements are appropriate and necessary for wells that would

inject into non-USDWs above and between USDWs. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information
on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25197

Comment: Y. Finally, EPA seeks comment on whether the Agency should set a minimum 

injection depth requirement for CO2 GS, rather than require that such injection 

take place below the lowermost USDW. 

NYSDEC-DMN Response: It is NYSDEC-DMN’s opinion that the EPA should not set a 

minimum injection depth requirement for CO2 GS operations. The decision to 

permit a project should be made on a site- specific basis and evaluation. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects.

EPA believes that a determination of site-suitability for GS (i.e., that subsurface formations will

receive and confine injected CO2) should be made on a site-specific basis. The GS rule, at §146.82,

requires the owner or operator to provide extensive site- and project-specific information to the

Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be

contained within the injection formation, and that USDWs will be protected from endangerment. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24349

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW 

Comment: 6. Injection Depth 

As already discussed, we oppose restricting Class VI injection to either to any 

minimum injection depth or to injection zones below the lowermost USDW. As EPA 

recognizes, 73 Fed. Reg. at 43511-12, such restrictions are not necessary to 

protect USDWs and would serve only to preclude the use of what might otherwise 

be appropriate CO2 storage reservoirs. EPA should permit GS under any 

circumstances in which the Director can determine that USDWs will not be 

endangered. 
Recognizing that the USDW definition is so broad as to include formations that - 

because of their location, depth, or other factors - could not reasonably be 

expected to serve as sources of drinking water, we support the appropriate use 

of aquifer exemptions to facilitate GS. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects.

EPA believes that a determination of site-suitability for GS (i.e., that subsurface formations will

receive and confine injected CO2) should be made on a site-specific basis. The GS rule, at §146.82,

requires the owner or operator to provide extensive site- and project-specific information to the

Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be

contained within the injection formation, and that USDWs will be protected from endangerment. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24533

Comment: Rule Provisions or Federal Register Cite: 73 FR 43512 

EPA Preamble Question: 26. EPA seeks comment on whether the Agency should set a 

minimum injection depth requirement for CO2 GS, rather than require that such 

injection take place below the lowermost USDW. EPA Notice 43512. 

CSC Response: There should be no minimum depth for injection of CO2. The primary 

consideration should be protection of USDWs. A requirement for a minimum depth 

suggests an intention by EPA to require injection of CO2 in a supercritical 

phase. Such a requirement is not appropriate since there may be areas where 

injection of CO2 in other phases may be the only option. Again, site-specific 

evaluation and protection of USDWs should be the basis for determining depth of 

injection. 

Response: As described above, EPA agrees that it is not appropriate to set a minimum injection

depth for GS projects or require that the CO2 be injected in a supercritical state. The final GS rule at

§146.95 establishes a process by which owners or operators can seek a waiver of the Class VI

injection depth requirements for injection into non-USDW formations above and/or between

USDWs.

Commenter Name: John R. Baza Letter ID: 0193

Commenter Organization: Utah Division of Oil, Gas, and Mining Comment ID: 23914
Other EPA Comment Codes and Descriptions: 4120 2.4.1.2 Allowing hydraulic fracturing during

GS (seeking comment); 4490 2.4.5 Use of tracers and potential impact on human health or

ecosystems (seeking comment) 

Comment: Operating Requirements 

EPA seeks comments on hydraulic fracturing, minimum depth requirements, and the 

potential impact of tracer use on human health and the environment. The Division 

concurs with the IOGCC recommendations (included in their December 23, 2008 

comments) that while hydraulic fracturing may be necessary for well completion, 

measures should be taken to prevent any fracturing of the confining zone. No 

minimum depth for GS should be specified and once again should be done on a 

site-specific basis. Use of tracers should be at the discretion of the 

regulating agency. 

Response: The final rule allows the use of hydraulic fracturing at Class VI well sites, where

approved by the Director. Hydraulic fracturing is one of several stimulation technologies available to

improve wellbore and formation injectivity. 

EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director.

Owners or operators must submit a proposed stimulation program as part of the permit application

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

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

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

perform stimulation only as approved. 

The final rule at §146.91(d)(2) also requires that the owner or operator notify the Director 30 days

before performing stimulation during the operational phase of a GS project; this will provide an

additional opportunity for the 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.

In addition, to maintain the integrity of the confining zone, the final rule requires that, except during

stimulation, the injection pressure not exceed 90 percent of the fracture pressure of the injection

zone.

EPA also agrees that it is not appropriate to set a minimum injection depth for GS projects and the

Agency believes that a determination of site-suitability for GS (i.e., that subsurface formations will

receive and confine injected CO2) should be made on a site-specific basis. The GS rule at §146.82

requires the owner or operator to provide extensive site- and project-specific information to the

Director to demonstrate that the site meets the minimum siting criteria at §146.83 and that the CO2

will be contained within the injection formation and that USDWs will be protected from

endangerment. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective
of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Finally, EPA agrees that the use of tracers should not be required at all GS sites, but should be

available as an option. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment. The rule

will also allow their use if proposed by the owner or operator and approved by the Director.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24596

Comment: Rule Provisions: 73 FR 43512 

EPA Rule Issue: 26. EPA seeks comment on whether the Agency should set a minimum 

injection depth requirement for CO2 GS, rather than require that such injection 

take place below the lowermost USDW. EPA Notice 43512. 

Anadarko Petroleum Corporation (APC) Response: There should be no minimum depth 

for injection of CO2. The primary consideration should be protection of USDWs. A 

requirement for a minimum depth suggests an intention by EPA to require 

injection of CO2 in a supercritical phase. Such a requirement is not appropriate 

since there may be areas where injection of CO2 in other phases may be the only 

option. Again, site-specific evaluation and protection of USDWs should be the 

basis for determining depth of injection. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects or

require that the CO2 be injected in a supercritical state. EPA believes that a determination of sitesuitability for GS (i.e., that subsurface formations will receive and confine injected CO2) should be

made on a site-specific basis. The GS rule, at §146.82, requires the owner or operator to provide

extensive site- and project-specific information to the Director to demonstrate that the site meets the

minimum site criteria at §146.83, that the CO2 will be contained within the injection formation, and

that USDWs will be protected from endangerment. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.
Commenter Name: Chris M. Hobson Letter ID: 0201

Commenter Organization: Southern Company Comment ID: 22164

Comment: There is also no need for a minimum injection depth requirement for CO2 GS 

projects, provided that protection of USDWs can be demonstrated. ¡d. at 43512. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site-specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: John Corra Letter ID: 0205

Commenter Organization: Wyoming Department of Environmental Quality

(DEQ)

Comment ID:

22196

Comment: 2. Requiring a minimum depth of injection: 

a. Given the variety in subsurface geologic conditions that exist both within, 

and between states, we would not support setting a minimum injection depth 

requirement for CO2 GS in lieu of requiring that such injection take place below 

the lowermost USDW. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific
information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Christopher Murray Letter ID: 0207

Commenter Organization: Pacific Northwest National Laboratory Comment ID: 22453

Comment: - GS is better served by neither mandating a set minimum depth for injection nor 

by requiring injection take place below the lowermost USDW. Minimum depth 

requirements would be unnecessarily proscriptive . Shallow injections could be 

done for very small commercial producers or in cases where reservoir engineering 

practices (such as pre-dissolution of the CO2into formation water) are done so 

that no free CO2 phase exists. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Richard Guinn Letter ID: 0210

Commenter Organization: Eastman Chemical Company Comment ID: 22734

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW 

Comment: EPA seeks comment on whether the Agency should set a minimum injection depth 

requirement for CO2 GS, rather than require that such injection take place below 

the lowermost USDW. EPA Notice 93. 

EPA should neither require injection below the lowermost USDW nor alternately 

require a minimum depth requirement as geologic structures are likely to be 
encountered that provide for secure and safe storage. Examples of such storage 

that should be acceptable are domes and caverns. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Edward Steadman Letter ID: 0220

Commenter Organization: The Energy and Environmental Research Center at the

University of North Dakota

Comment ID:

21624

Comment: evaluated on a site-specific basis. Furthermore, minimum depths should not be 

required. Again, this should be site-specific. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to
comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21688

Comment: A containment system with appropriate site characterization, risk assessment and 

monitoring is the key to secure storage and protection of USDWs. Proximity of 

the injection zone to USDWs (i.e. whether shallower or deeper) is not the 

appropriate criteria for protection of USDWs because proximity alone does not 

materially impact risk of leakage. Similarly, EPA should not establish minimum 

depths for CO2 injection. Instead, any constraints placed on injection should be 

site-specific, consistent with the containment and capacity parameters of the 

storage site in question. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21690

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW 

Comment: In summary, EPA should not mandate a requirement of injection only below the 

lower-most USDW nor a minimum depth for injection of CO2. Such a comprehensive 

prohibition would unjustifiably exclude potential storage sites that do not pose 

an endangerment to USDWs. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,
that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21739

Comment: A containment system with appropriate site characterization, risk assessment and 

monitoring is the key to secure storage and protection of USDWs. Proximity of 

the injection zone to USDWs (i.e. whether shallower or deeper) is not the 

appropriate criteria for protection of USDWs because proximity alone does not 

materially impact risk of leakage. Similarly, EPA should not establish minimum 

depths for CO2 injection. Instead, any constraints placed on injection should 

be site-specific, consistent with the containment and capacity parameters of the 

storage site in question. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.
Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21741

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW 

Comment: In summary, EPA should not mandate a requirement of injection only below the 

lower-most USDW nor a minimum depth for injection of CO2. Such a comprehensive 

prohibition would unjustifiably exclude potential storage sites that do not pose 

an endangerment to USDWs. 

Response: As described above, EPA agrees that it is not appropriate to set a minimum injection

depth for GS projects and the Agency believes that a determination of site-suitability for GS (i.e.,

that subsurface formations will receive and confine injected CO2) should be made on a site-specific

basis. EPA also acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs, as long as appropriate

protections are in place. The final GS rule at §146.95 establishes a process by which owners or

operators can seek a waiver of the Class VI injection depth requirements for injection into nonUSDW formations above and/or between USDWs.

Commenter Name: Robert E. Carter Jr. Letter ID: 0236

Commenter Organization: Indiana Department of Natural Resources (IDNR) Comment ID: 29220

Comment: States like Indiana with a proven track record of effectively managing similar 

programs have indeed demonstrated an ability to adapt to evolving technologies 

and we believe do possess the capability to effectively address long-term 

storage issues. In fact, as indicated earlier in our comments, many of the longterm issues associated with CCGS operations will be outside the purview of the 

UIC Program and will need to be addressed by states as they enact appropriate 

CCGS legislation. EPA should consider implementing rules which afford states 

with the greatest flexibility to select regulatory options that are best suited 

to their specific needs and conditions. Specific examples of requirements that 

may be too prescriptive include: 

5. Any requirement to establish minimum injection depth requirements. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule at §146.82 requires the owner or operator to provide extensive site and project-specific

information to the Director to demonstrate that the site meets the minimum siting criteria at §146.83

and that the CO2 will be contained within the injection formation and that USDWs will be protected

from endangerment.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23248

Comment: 26. EPA seeks comment on whether the Agency should set a minimum injection depth 

requirement for CO2 GS, rather than require that such injection take place below 

the lowermost USDW. EPA Notice 43512. 

There should not be a minimum injection depth. The determining factor should be 
whether the project will be protective of USDWs. A minimum depth requirement 

suggests a requirement to inject carbon dioxide in a supercritical phase. This 

is not appropriate since there may be projects where injection of carbon dioxide 

in other phases is the most effective option. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24816

Comment: EPA Notice Questions: 73 FR 43512 

EPA Rule Issue: 26. EPA seeks comment on whether the Agency should set a minimum 

injection depth requirement for CO2 GS, rather than require that such injection 

take place below the lowermost USDW. EPA Notice 43512. 

GWPC CO2 Committee Response: There should not be a minimum depth established AND 

there should be no blanket restriction concerning proximity to USDWs but should 

instead be based on ability to protect USDWs. 

Rationale: The presence of numerous oil and gas reservoirs above demonstrates 

the ability of geologic formations at those depths to trap and contain fluids 

comparable to CO2 streams. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.
EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22812

Comment: III A. 4 Proposed Injection Well Operating Requirements 

AA. Finally, EPA seeks comment on whether the Agency should set a 

minimum injection depth requirement for CO2 GS,rather than require that such 

injection take place below the lowermost USDW. 

IOGCC Response: EPA should not set a minimum injection depth requirement for CO2 GS 

as it is unnecessary. The rule needs to allow site specific flexibility. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Brian Williams Letter ID: 0507

Commenter Organization: BP Alternative Energy Comment ID: 21167
Comment: Secondly, a minimum injection depth versus a requirement to inject below the 

lowermost USDW, we could disagree that the universal mandate for establishing 

minimum depth for CO2 injection as there should be site-specific ones again 

based on the containment and capacity parameters of the storage site itself. 

Response: EPA agrees that it is not appropriate to set a minimum injection depth for GS projects

and the Agency believes that a determination of site-suitability for GS (i.e., that subsurface

formations will receive and confine injected CO2) should be made on a site-specific basis. The GS

rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83,

that the CO2 will be contained within the injection formation, and that USDWs will be protected

from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Kevin Frederick Letter ID: 0525

Commenter Organization: Wyoming Department of Environmental Quality Comment ID: 21404

Other EPA Comment Codes and Descriptions: 2163 1.6.3.1 Comments in favor of injection into

unmineable coal seams 

Comment: Given the variety of sub-surface geologic conditions that exist both within and 

between states, we would not support setting a minimum injection depth 

requirement for CO2 geologic sequestration in lieu of requiring that such 

injection take place below the lower most USDW. 

We do not support prohibiting the injection of CO2 for long term storage into 

certain formations where they are above the lowermost USDW. As mentioned before, 

we believe there are likely circumstances where injection into formations 

including deep or mineable coal seams situated above the lower most USDW may be 

practical and protective of overlying and underlying USDW's. 

Response: EPA clarifies that the GS rule does not preclude injection into any non-USDWs

formations, including coal seams, provided the site-suitability requirements in the GS rule are met.

EPA acknowledges that there may be risks associated with GS into certain formation types. For this

reason, the Agency is using an adaptive approach to regulate GS injection. EPA will collect and

review project data on early GS projects, including those that inject into various formation types, to

determine whether the appropriate amount and types of information and documentation are being

collected. EPA plans, every six years, to collect and review data on GS projects to determine whether

the appropriate amount and types of information and appropriate documentation are being collected,
and to determine if modifications to the requirements are appropriate or necessary.

EPA agrees that it is not appropriate to set a minimum injection depth for GS projects and the

Agency believes that a determination of site-suitability for GS (i.e., that subsurface formations will

receive and confine injected CO2) should be made on a site-specific basis. The GS rule, at §146.82,

requires the owner or operator to provide extensive site- and project-specific information to the

Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be

contained within the injection formation, and that USDWs will be protected from endangerment.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Talib Syed Letter ID: 0537

Comment ID: 21474

Other EPA Comment Codes and Descriptions: 4400 2.4.4.3 Allowing injection above or between

USDWs (seeking comment) 

Comment: Another item that I would like to bring to you know, to be considered is the 

depth of the lower most USDW. Yes in an ideal world, you want to have your 

injection zone below your lower most USDW, but what happens if you have USDW say 

at 20,000 feet? Nobody is using that USDW for practical purposes. You are not 

going to go and drill a water well 20,000 feet deep in order to supply a 

community, but at the same time it meets the criteria of less than 10,000 TDS. 

So there should be some flexibility on a case by case basis. Either if it is 

economically not feasible or it is technologically not feasible just as we have 

an aquifer exemption process or you know, for the Class II program. But I do 

prefer as a starting point that you use a zone that is you know, deeper than 

your lower most USDW, but not in every instance as mandatory requirement. 

Response: EPA is not changing the USDW definition; changing the definition of a USDW is

outside the scope of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as

required under the SDWA, by establishing regulations to ensure the safe injection of CO2 for longterm storage.

EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. Specifically, the Director must consider whether alternative

injection sites are available; community needs, demands, and supply from drinking water resources;
planned needs, potential and/or future use of USDWs and non-USDWs in the area; and a plan for

securing alternative resources or treating USDW formation waters in the event of contamination

related to the Class VI injection activity. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Comment Code: 4400 2.4.4.3 Allowing injection above or between USDWs (seeking comment) 

Individual Comments

Commenter Name: Anonymous2 Letter

ID: 0133

Commenter Organization: Sierra Club National Global Warming and Energy

Committee and Sierra Club California-Nevada Regional Conservation Committee on

Energy and Climate Change

Comment

ID: 21580

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 2120

1.6.1 Deep saline formations 

Comment: USDWs and Exempted Aquifers: Re-evaluate the UIC program's current definition of 

Underground Source of Drinking Water (at 40 CFR 146.3), as applied to Criteria 

for Exempted Aquifers (at 40 CFR 146.4), in regards to the EPA's total dissolved 

solids (TDS) standard of <10,000 mg/L. 

Response: The Agency acknowledges commenter concerns about water resources and future water

resource availability. However, modifying the definition of a USDW is outside the scope of the GS

rulemaking. USDWs are defined as aquifers currently being used as sources of drinking water or

those capable of supplying a public water system and they have a total dissolved solids (TDS)

content of 10,000 milligrams per liter or less (§144.3). 

The primary goal of the UIC Program under the SDWA is to protect USDWs in order to ensure a

reliable supply of drinking water for the American public. The GS rule, as part of the UIC program

regulations, continues the program’s statutory mandate of ensuring the protection of USDWs. The

permitting, siting, construction, operation, monitoring, and post-injection site care requirements in

the GS rule built on a long-standing protective regulatory framework, tailored to the unique

characteristics of CO2 GS. 

EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. Specifically, the Director must consider whether alternative

injection sites are available; community needs, demands, and supply from drinking water resources;

planned needs, potential and/or future use of USDWs and non-USDWs in the area; and a plan for

securing alternative resources or treating USDW formation waters in the event of contamination

related to the Class VI injection activity.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22549
Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: Definition of Underground Sources of Drinking Water 

NGWA recommends that US. EPA reevaluate the appropriateness of the definition of 

an underground source of drinking water (USDW) as one containing less than 

10,000 ppm total dissolved solids prior to large-scale licensing of carbon 

capture and storage (CCS) sites to ensure future drinking water supplies are not 

unintentionally degraded. For example, a recent article reported that deep 

brackish ground water, approximately 12,000 TDS, is under consideration as a 

water source for a development in Sandoval County, New Mexico. The article 

notes that the cost of water treatment is expected to be less than obtaining 

existing water rights (Sengebush, 2008) In 2003, water managers in 36 states 

anticipated shortages in localities, regions, or statewide in the next ten years 

(U.S. General Accounting Office, 2003). The potential for the increased use of 

brackish ground water for water supplies must be anticipated and considered. 

Sengebush, Robert M., INTERA, Inc. Deep Brackish Water Considered for New 

Mexico Development. Southwest Hydrology, March/April 2008, p. 8. 

U.S. General Accounting Office. Freshwater Supply: States’ Views of House 

Federal Agencies Could Help Them Meet the Challenges of Expected Shortages 

(GAO-03-514). July 2003, p. 1. 

Response: EPA is not changing the USDW definition; changing the definition of a USDW is

outside the scope of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as

required under the SDWA, by establishing regulations to ensure the safe injection of CO2 for longterm storage.

EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. Specifically, the Director must consider whether alternative

injection sites are available; community needs, demands, and supply from drinking water resources;

planned needs, potential and/or future use of USDWs and non-USDWs in the area; and a plan for

securing alternative resources or treating USDW formation waters in the event of contamination

related to the Class VI injection activity.

Commenter Name: James Childress Letter ID: 0158

Commenter Organization: Gasification Technologies Council (GTC) Comment ID: 23774

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4660 2.6.6 Geochemical monitoring 

Comment: §146.90 Testing and monitoring requirements. (d) Periodic monitoring of the 

ground water quality and geochemical changes above the confining zone(s) that 

may be a result of carbon dioxide movement through the confining zone or 

additional identified zones: 

We recommend changing to "Periodic monitoring of the ground water quality and 

geochemical changes between the confining zone(s) and the USDW that may be a 
result of carbon dioxide movement through the confining zone or additional 

identified zones:" This rewording is consistent with allowing for injection 

either above or below USDWs 

Response: EPA disagrees that the GS rule should specify the zones to be monitored. EPA clarifies

that §146.90(d) requires periodic monitoring of the ground water quality and geochemical changes

above the confining zone(s). EPA clarifies that this monitoring requirement does not include the

confining layer itself. Monitoring above the confining layer will provide an indication of upward

movement of CO2 that might endanger a USDW. The exact number of formations to be tested will,

however, be based on site-specific characteristics and vulnerabilities and described in the Directorapproved testing and monitoring plan. 

EPA is developing guidance on testing and monitoring to assist owners or operators and Directors in

evaluating requirements under §146.90, including proposed monitoring plans. 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 the final GS rule, owners or operators granted injection depth waivers are subject to additional

requirements at §146.95(f)(3) to monitor above and below the injection zone in order to ensure

protection of USDWs underlying and overlying the injection zone during both well operation and the

post-injection site care period. 

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24134

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 2046

1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ dividing line between Class

II and Class VI (seeking comment) 

Comment: Rule Provision: 144.6 

API Comments: Sections 144.6 - Classification of Wells: 

(b) Class II. Wells which inject fluids:... 

(4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC

SEQUESTRATION IS 

OCCURRING DURING OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR

NATURAL GAS 

PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE THAN INSIGNIFICANT

FUTURE 

PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION

AND (II) 

OPERATING PRESSURES ARE NO HIGHER THAN REASONABLY NECESSARY TO

PRODUCE SUCH 

VOLUMES OR RATES; AND 
(5) FOR GEOLOGIC SEQUESTRATION IN OIL AND GAS FORMATIONS AND WHERE THE

CRITERIA 

OF PARAGRAPH (B)(4) ARE NOT MET 

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon 

dioxide STREAMS. beneath the lowermost formation containing a USDW WELLS 

WHERE GEOLOGIC SEQUESTRATION OF CO2 STREAMS OCCURS DURING OR IN

CONNECTION WITH 

EOR OR EGR ARE REGULATED UNDER CLASS II. 

Rationale: Additionally, there should not be a blanket prohibition concerning 

injection above USDW’s or at specific depths. This is especially true given the 

possibility of changes in the definition of a USDW to include formations greater 

than 10,000 parts per million Total Dissolved Solids. This requirement is not 

necessary for the protection of USDWs and would remove a vast number of viable 

formations from consideration. Industry has shown that it can operate CO2 

injection wells in an EOR context without endangering USDWs that are located 

below the injection zone. An excellent example is the Salt Creek EOR project in 

Wyoming, which has a USDW below the injection zone. Moreover, under the proposed 

rule, there are other measures that would provide real assurance of formation 

integrity and require operators to demonstrate that their project will not 

endanger USDWs, making the lowermost USDW restriction unnecessary. 

Response: EPA did not make the suggested change. EPA clarifies that the final rule requires that

injection for GS be into non-USDWs below the lowermost USDW; however, owners or operators

may apply for a waiver from this requirement, as described in §146.95. For more information, see

the discussion of waivers in the preamble to the final rule.

The Agency disagrees that wells injecting CO2 for the primary purpose of long-term storage should

be regulated under Class II requirements. The Agency believes that the nature and risks of CO2

injection for the primary purpose of long-term storage pose different risks than injection for the

primary purpose of ER, and therefore has developed new Class VI regulations to address these

unique risks. For example, the volume of CO2 anticipated to be injected for long-term storage is

significantly greater than for ER operations. Reservoir pressure conditions will also be different, with

Class VI injection operations involving large volumes of CO2 and likely having higher pressures

within their storage formations than Class II ER projects. 

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

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

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

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

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

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

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

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

allowing for site-specific flexibility. For more information, please see the discussion on transition of

Class II wells in the preamble to the final GS rule.

EPA is developing guidance on transitioning permits from Class II to Class VI. The guidance will
assist Directors in determining whether an injection project should be transitioned from Class II,

where the primary purpose is oil and gas production, to Class VI, where the primary purpose is longterm storage of large volumes of CO2. The guidance describes the recommended methods the

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

determine whether a project should be regulated within the Class II or Class VI UIC program. This

guidance will be available on EPA’s website at

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

Commenter Name: James Taft Letter ID: 0172

Commenter Organization: Association of State Drinking Water Administrators

(ASDWA)

Comment ID:

23451

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: Potential USDW Above 10,000 TDS: 

Since states and water utilities in many areas of the U.S. are currently 

addressing drought and water rights and availability issues, the proposed rule 

should provide for states to include protections for well sites with potentially 

viable sources of drinking water, such as saline aquifers and aquifers above 

10,000 (mg/L) total dissolved solids (TDS) level that might serve as a viable 

drinking water source. ASDWA recommends that states be allowed regulatory 

flexibility to consider these aquifers as potential drinking water sources. 

Please note that there is some variance among states with regard to this issue. 

While some states would like Congress to consider changing the current Safe 

Drinking Water Act (SDWA) language to preclude these aquifers as potential 

sequestration sites, other states are actively looking for additional 

sequestration sites and would prefer that the proposed regulation and the 

current Safe Drinking Water Act (SDWA) language keep the current 10,000 TDS 

(mg/L) definition for a USDW. Thus, we recommend state-specific flexibility on 

this matter. 

Response: EPA is not changing the USDW definition; changing the definition of a USDW is

outside the scope of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as

required under the SDWA, by establishing regulations to ensure the safe injection of CO2 for longterm storage. 

EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. Specifically, the Director must consider whether alternative

injection sites are available; community needs, demands, and supply from drinking water resources;

planned needs, potential and/or future use of USDWs and non-USDWs in the area; and a plan for

securing alternative resources or treating USDW formation waters in the event of contamination

related to the Class VI injection activity. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Quinlan J. Shea Letter ID: 0177
Commenter Organization: Edison Electric Institute Comment ID: 23582

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: A related issue is how USDW are to be defined under the proposed rules. Current 

UIC regulations, as well as the preamble to the proposed rules, define USDW as: 

An aquifer or portion of an aquifer that supplies any public water 

system or that contains a sufficient quantity of ground water to supply 

a public water system, and currently supplies drinking water for human 

consumption, or that contains fewer than 10,000 mg/l total dissolved 

solids and is not an exempted aquifer. 

EEI recommends that the Agency work within the current definition of USDW, in 

particular its maximum total dissolved solids (TDS) provision, for purposes of 

CO2 injection and storage. Any change in the definition of USDW would likely 

require a statutory amendment. The legislative history of SDWA identifies the 

10,000 TDS standard as one sufficient to ensure that potential drinking water 

sources that may be tapped in the future are protected,[FN6] and EPA has long 

recognized this standard in its regulations without any serious suggestion over 

the long and successful history of the UIC program that the standard is 

inadequate. Thus, any potential alteration to that standard (which implicates a 

range of public policy issues) should be left to Congress. Some have called for 

potential revision to this standard, but EEI is unaware of any analysis 

supporting the establishment of an alternative standard. Nor is EEI aware of 

any evaluation of the implications of changing this standard for long-standing 

UIC activities, much less on the practicability of CCS as a critical GHG 

mitigation tool. In short, even if Congress‘s original expression of the 10,000 

mg/l standard did not constrain EPA‘s ability to change this standard by 

regulation, EEI is unaware of any foundation in the administrative record that 

would allow EPA to provide reasoned support for such a change. 

[FN6] See H.R. Rep. 93-1185 (1974), reprinted in 1974 U.S.C.C.A.N. 6454, 6484. 

Response: EPA is not changing the USDW definition; changing the definition of a USDW is

outside the scope of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as

required under the SDWA, by establishing regulations to ensure the safe injection of CO2 for longterm storage. 

EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. Specifically, the Director must consider whether alternative

injection sites are available; community needs, demands, and supply from drinking water resources;

planned needs, potential and/or future use of USDWs and non-USDWs in the area; and a plan for

securing alternative resources or treating USDW formation waters in the event of contamination

related to the Class VI injection activity. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.
Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23647

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: - The 10,000 mg/l TDS limit for classifying USDWs for the siting of Class VI 

wells needs to be revised upward. 

Response: EPA is not changing the USDW definition; changing the definition of a USDW is

outside the scope of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as

required under the SDWA, by establishing regulations to ensure the safe injection of CO2 for longterm storage.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23661

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: USDW Classification: The best sources of drinking water are already being used 

by utilities. In many areas, population growth is forcing utilities to look 

further or to look at more challenging sources. With the potential impacts from 

climate change, drinking water utilities are facing an even more limited supply 

of fresh drinking water. As a result, many utilities are turning to more 

challenging groundwater sources such as those that are very deep or have high 

salinity concentrations. Additionally, the pumping costs for these deep wells 

are no longer prohibitive given the lack of sufficient water sources. Some of 

these new sources could fall outside of the current definition of a USDW, in 

that the aquifer has a TDS concentration higher than 10,000 ppm. The proposed 

rule promises protection of USDWs from endangerment, in that the activity does 

not cause a primary drinking water Maximum Contaminant Level (MCL) to be 

exceeded in an USDW or affect human health. There are no anti-degradation 

provisions in the proposed regulation to protect other groundwater supplies, 

such as those aquifers that are not classified as a USDW but have been, or may 

be, identified as a future drinking water source. The definition of a USDW was 

written at a time when many advanced water treatment technologies were generally 

cost prohibitive, and the general thinking that the high-salinity aquifers would 

never be utilized as drinking water sources. 

Technological advances in the area of desalination have reduced many of the 

treatment costs, making it more and more accessible. Many utilities have no 

other choice for new water sources. Ever increasing population and water demands 

have utilities using non-traditional and poorer water sources (see Table 1-1 for 

examples; note that this is not meant to be a comprehensive list of all 

desalination plants in the United States). 

Table 1-1: Water Utilities with More Challenging Water Sources 

[The information below was originally presented as a table. See Docket PDF EPAHQ-OW-2008-0390-0181 to see a copy of the original table.] 

Utility Name: El Paso Water Utilities and Ft.Bliss, Texas 

Water Source: Hueco Bolson Basin 
Usage: 27.5 mgd 

TDS Concentrations: 600 to 4,900 mg/l 

Utility Name: Tampa Bay Water, Florida 

Water Source: Seawater 

Usage: 25 mgd 

TDS Concentrations: 18,000 - 32,000 mg/L 

Utility Name: Yuma Desalting Plant, Arizona 

Water Source: Drainage water 

Usage: 22 mgd 

TDS Concentrations: 3,200 mg/L 

Utility Name: Miami-Dade County, Florida 

Water Source: Florida Aquifer 

Usage: 17.5 mgd (currently under design) 

TDS Concentrations: 1,000 - 5,000 mg/L 

Utility Name: Temescal Desalter Project, California 

Water Source: Temescal Basin 

Usage: 15 mgd 

TDS Concentrations: 700 mg/L 

Utility Name: City of Abilene, Texas 

Water Source: Surface water 

Usage: 8.0 mgd 

TDS Concentrations: 1,200 mg/L 

Utility Name: City of Sherman, Texas 

Water Source: Surface water 

Usage: 7.5 mgd 

TDS Concentrations: 900 - 1500 mg/L 

Utility Name: Southmost Regional Water Authority, Texas 

Water Source: Groundwater 

Usage: 6.75 mgd 

TDS Concentrations: 3,500 mg/L 

Utility Name: Lake Granbury SWATS,Texas 

Water Source: Surface water 

Usage: 6.0 mgd 

TDS Concentrations: 1,800 mg/L 

Utility Name: City of Fort Stockton, Texas 

Water Source: Groundwater 

Usage: 6.0 mgd 

TDS Concentrations: 1485 mg/L 

Utility Name: Newport News WTP, Virginia 

Water Source: Lower and Middle Potomac Aquifers 
Usage: 5.7 mgd 

TDS Concentrations: 3600 mg/L 

Utility Name: Alameda County Water District, California 

Water Source: Niles Cone Groundwater Basin 

Usage: 5.0 mgd with expansion to 10 mgd 

TDS Concentrations: 1,100 - 2,400 mg/L 

Utility Name: Pascagoula, Mississippi 

Water Source: Groundwater 

Usage: 4.5 mgd 

TDS Concentrations: 1,000 mg/L 

Utility Name: Dare County North WTP, North Carolina 

Water Source: Groundwater 

Usage: 3.0 mgd 

TDS Concentrations: 4,300 mg/L 

Utility Name: Port Hueneme Brackish Water Facility, California 

Water Source: Groundwater 

Usage: 3.0 mgd 

TDS Concentrations: 1,300 mg/L 

Utility Name: James City Service Authority, Virginia 

Water Source: Middle and Lower Potomac Aquifers 

Usage: 2.5 mgd 

TDS Concentrations: 1,000 - 2,400 mg/L 

Utility Name: Buxton, North Carolina 

Water Source: Groundwater 

Usage: 2.0 mgd 

TDS Concentrations: 13,200 mg/L 

Utility Name: Cape May, New Jersey 

Water Source: Groundwater 

Usage: 2.0 mgd 

TDS Concentrations: 2,100 mg/L 

Utility Name: Dare County Cape Hatteras WP, North Carolina 

Water Source: Groundwater 

Usage: 2.0 mgd 

TDS Concentrations: 11,200 mg/L 

Utility Name: Las Animas, Colorado 

Water Source: Groundwater 

Usage: 1.18 mgd 

TDS Concentrations: 3,500 mg/L 

Utility Name: VA Medical Center, Ft. Lyon, Colorado 

Water Source: Groundwater 
Usage: 0.24 mgd 

TDS Concentrations: 800 mg/L 

The use of very deep and/or high salinity groundwater becoming more commonplace 

is only a matter of time. Therefore, we believe the 10,000 mg/L TDS USDW 

definition is no longer appropriate. Given that this regulation does not 

currently extend protection to non-traditional and poorer water sources, AWWA 

believes that these aquifers may be adversely impacted by this rulemaking. These 

aquifers, which have not been previously used as a drinking water source, may be 

in the future, and it is important to make sure that they are adequately 

protected. AWWA recommends that EPA consider the "green-effect" and that, in 

many cases, the overall least cost alternative may be to treat brackish 

groundwater using desalination technology instead of trying to obtain surface 

water as the drinking water source. While the surface water may be less 

expensive to treat, if the utility is located in a dry environment, such as 

Arizona or New Mexico, the pumping costs to transport that water over a large 

distance may be much larger than the cost to treat a brackish groundwater. EPA 

should also consider that as technology evolves, utilities will be able to treat 

a much different set of waters than is currently being treated. Several 

utilities are using sea water or brackish water as drinking water sources, which 

would not have been even remotely considered as a viable option 20 years ago, 

when the TDS limit was originally developed. 

Recognizing that it is difficult to extend protection to these aquifers due to 

the restrictions of the SDWA, AWWA recommends that the regulation be revised to 

mandate that, during the project planning process, the owner/operators should 

include state environmental departments as they can provide insight into what 

aquifers currently (not classified as USDWs) might be considered as future 

drinking water sources. The stakeholder process should also involve both 

regional and local planning boards, as well as the local utilities. This process 

will allow for protection to be extended to the non-traditional aquifers, which 

will be necessary given the pressures on water resources that the country will 

be facing in the upcoming century. 

Response: As described above, EPA is not changing the USDW definition; changing the definition

of a USDW is outside the scope of the GS rulemaking. The GS rule focuses on ensuring protection

of USDWs, as required under the SDWA, by establishing regulations to ensure the safe injection of

CO2 for long-term storage.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23662

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 1610

1.3.1 Risks to USDWs 

Comment: USDW Endangerment: AWWA recommends revision to the definition of

"endangerment" 

in the proposed rule. The current definition of endangerment is limited to SDWA 

UIC definition of 10,000 TDS and to primary MCL contamination. Certain healtheffects can be related to concentrations in water of compounds that do not 
exceed the primary MCL. However, under the current language, these potential 

contaminants would not be covered with the protections afforded by the SDWA. 

Response: The Agency acknowledges commenter concerns about water resources and future water

resource availability. However, modifying the definition of a USDW or “endangerment” is outside

the scope of the GS rulemaking. USDWs are defined as aquifers currently being used as sources of

drinking water or those capable of supplying a public water system and they have a total dissolved

solids (TDS) content of 10,000 milligrams per liter or less as specified in §144.3. EPA adds that

concerns about contaminants with health effects even at concentrations below the maximum

contaminant level should be addressed as part of the review process for the national primary

drinking water regulations; such concerns are outside the scope of this rulemaking. Please note that

the definition of “endangerment” has been defined by Congress at SDWA §1421(d)(1)(2). 

The primary goal of the UIC Program under the SDWA is to protect USDWs from endangerment in

order to ensure a reliable supply of drinking water for the American public. The GS rule, as part of

the UIC program regulations, continues the program’s mandate of ensuring the protection of

USDWs. EPA expects the tailored permitting, siting, construction, operation, monitoring, and postinjection site care requirements in the GS rule to prevent leakage from injection formations and

protect USDWs.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23667

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: Safe Drinking Water Act Authority: In its February 2008 stakeholders meeting, 

EPA seemed to imply that it was restricted in what it could regulate and/or 

require under the SDWA for UIC projects to preventing "endangerment of USDW." 

AWWA recognizes that EPA’s regulatory authority is limited by the requirements 

of the SDWA and will be advocating that several portions of the SDWA be amended 

to better protect the nation’s groundwater resources. Issues that we will be 

addressing include: 

1. The definition of a USDW is provided within the SDWA, which may require 

amendment if the quality and accessibility groundwater sources is to be 

protected. We recognize that the 10,000 mg/L TDS limit is very outdated, and 

that a new upper limit should be established and applied when siting Class VI 

wells. We hesitate to recommend any specific number at this point in time, given 

that some drinking water utilities are so stressed for water resources that they 

are investigating extremely non-traditional water sources with high TDS levels. 

2. Endangerment is defined by the SDWA and may need to be redefined to protect 

beneficial uses. The proposed rule seems to be focused on preventing brine from 

the carbon dioxide storage formations from reaching USDWs and/or preventing 

carbon dioxide from contaminating USDWs and causing exceedences of primary MCLs. 

The protective measures of the proposed rule may not be adequate from a source 

water and beneficial use protection standpoint as other changes are likely to 

occur besides exceeding primary MCLs (e.g., increased Fe/Mn, TDS, and lowered pH 

- all of which have secondary MCLs and possible increase in silica and boron, 

which do not have MCLs, but have water quality significance). EPA needs to be 
provided with the regulatory authority to protect against these other types of 

endangerment, and the SDWA should be modified to allow for these protective 

measures to be developed. 

Response: As described above, EPA is not changing the USDW definition; changing the definition

of a USDW is outside the scope of the GS rulemaking. The GS rule focuses on ensuring protection

of USDWs, as required under the SDWA, by establishing regulations to ensure the safe injection of

CO2 for long-term storage.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23718

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: IV. COMMENTS ON RULE TEXT 

Part 144.6(f): Would "lowermost USDW" include formations that are not USDW’s at 

the point of injection but become USDW’s within the extent of the expected area 

of influence of the injection plume? AWWA recommends that these types of 

formations be included within the definition of USDW based on the ability of 

carbon dioxide to easily migrate within the confines of an aquifer. 

Response: EPA clarifies that the GS rule (and all of the UIC regulations) requires the protection of

all USDWs in the AoR of an injection activity. As part of the site characterization process and

during AoR delineation, owners or operators must identify all USDWs within the AoR, model the

full extent of the CO2 plume, and demonstrate that all USDWs within the AoR are protected from

endangerment. This would include USDWs that are laterally connected to non-USDWs, as suggested

by the commenter.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23720

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 1240

1.1.1.3 Suggested changes/edits to rule language 

Comment: Part 146.5(f): There is the possibility that some of the geologic sequestration 

activities will occur in areas where there are no USDWs located in the area of 

review. These wells should still be permitted as Class VI wells, and AWWA 

recommends revising the Class VI definition to: 

(f) Class VI. Wells used for geologic sequestration of carbon dioxide in the 

following applications: 

1. Where carbon dioxide is injected below the lowermost formation containing a 

USDW; and, 

2. Where carbon dioxide is injected in formations where no USDWs exist within 

the zone of elevated pressure associated with the injection well. 

Wells used for the geologic storage of carbon dioxide in formations above the 

lowermost USDW are prohibited. 

This definition would capture all wells associated with geologic carbon 

sequestration activities whether or not a USDW was present in the projected 
footprint of the project. 

Response: In the final rule EPA will allow injection into non-USDWs above or between the

lowermost USDW where owners or operators can demonstrate that such injection can be performed

in a manner that protects USDWs from endangerment, as long as appropriate protections are in

place. 

EPA adds that, in the final rule at §144.6 (f), Class VI wells are defined as wells that are not

experimental in nature that are used for geologic sequestration of carbon dioxide beneath the

lowermost formation containing a USDW; or, wells used for geologic sequestration of carbon

dioxide that have been granted a waiver of the injection depth requirements pursuant to requirements

at §146.95 of this chapter; or, wells used for geologic sequestration of carbon dioxide that have

received an expansion to the areal extent of an existing Class II enhanced oil recovery or enhanced

gas recovery aquifer exemption pursuant to §§146.4 of this chapter and 144.7(d).

Commenter Name: Wendy Jacobs Letter ID: 0183

Commenter Organization: Harvard Law School Environmental Law and Policy

Center

Comment ID:

25164

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: IV. EPA Should Update the Definition of USDW So that All Current and Viable

Future Drinking Water Supplies are Protected from GS.

EPA’s definition of what constitutes an "underground source of drinking water"

("USDW") is critical, because non-USDWs are not protected against potential

endangerment from GS operations under the proposed regulation.[FN14] EPA’s

continued use of a 1980 definition for USDWs, however, means that many nowviable sources of drinking water fall outside the technical definition of

"USDW," leaving valuable water supplies unprotected by the proposed UIC

regulation. See 73 Fed. Reg. at 43,492, 43,494. EPA should update the definition

of USDW to reflect the current state and foreseeable further advancement of

desalination technology. The definition of USDW should meet the statutory goal

of ensuring that all aquifers that "can reasonably be expected to supply any

public water system" are protected from potential contamination. See 42 U.S.C.

§300h (a)-(b), (d)(2).

[FN14] 40 C.F.R. §144.3 provides: "[U]SDW means an aquifer or its portion: (a)

(1) Which supplies any public water system; or

(2) Which contains a sufficient quantity of ground water to supply a public

water system; and

(i) Currently supplies drinking water for human consumption; or 

(ii)Contains fewer than 10,000 mg/L total dissolved solids; and 

(b) Which is not an exempted aquifer." 

Thus, the definition also excludes from "USDW" any aquifer that contains fewer

than 10,000 mg/L TDS but does not contain "a sufficient quantity of groundwater

to supply a public water system."

Since 1980, when EPA first promulgated the UIC regulations, "USDW" has been

defined narrowly to exclude any aquifer with waters containing more than 10,000

mg/L (also known as 10,000 p.p.m.) total dissolved solids (TDS). See
Consolidated Permit Regulations and Technical Criteria and Standards; State

Underground Injection Programs, 45 Fed. Reg. 42,472, 42,502 (June 24, 1980)

(Final Rule for 40 C.F.R. § 146 and Amendments to § 122; 40 C.F.R. §146.03

(1980)). This numerical limit is the creation of regulation, not statute: the

SDWA directed EPA to protect USDWs by publishing regulations for underground

injection control programs that include "minimum requirements for effective

programs to prevent underground injection which endangers drinking water

sources," which the SDWA defined to mean injection which may contaminate any

"underground water which supplies or can reasonably be expected to supply any

public water system." See 42 U.S.C. §300h(a)-(b), (d)(2) (emphasis added).

The legislative history supports the position that Congress intended these terms

to be construed broadly to effectuate Congress’s "overriding intent to maximize

protection of the public health." In a 1974 report accompanying the SDWA, the

House Committee on Interstate and Foreign Commerce explained:

[Section 1421 of the SDWA] . . . defines "underground injection which endangers

drinking water sources." It is the Committee’s intent that the definition be

liberally construed so as to effectuate the preventive and public health

protective purposes of the bill. The Committee seeks to protect not only

currently-used sources of drinking water, but also potential drinking water

sources for the future. This may include water sources which presently exceed

minimum intake water quality requirements or maximum contaminant levels or which

are not presently accessible for use as a community drinking water supply

source. 

Thus, for example, the Committee expects the [EPA] Administrator’s regulations

at least to require States to provide protection for subsurface waters having

less than 10,000 p.p.m. dissolved solids, as is currently done in Illinois and

Texas, even though water containing as much as 9,000 p.p.m. would probably

require treatment prior to human consumption.

Further contamination of such sources should not be permitted if there is any

easonable likelihood that these sources will be needed in the future to meet

the public demand for drinking water and if these sources may be used for such

purpose in the future. H. R. Rep. No. 93-1185, pt. C, at 32 (1974) (emphasis

added).

Thus, the House Committee offered the 10,000 mg/L standard, in 1974, as a

reference point. Then in 1980, EPA stated that it considered alternative

proposed concentrations to determine whether any offered "any superior

justification in terms of current State practice, human health, or technological

considerations," but found that none did. 45 Fed. Reg. at 42,483. Accordingly,

"[i]n the absence of any overriding argument to the contrary, the Agency will

follow the standard in the House Committee Report accompanying the SDWA." Id.

However, improvements in desalination technology since 1974 and 1980 provide

"superior justification" for increasing the 10,000 mg/L standard. Water with

TDS concentrations above 10,000 mg/L is desalinated using Reverse Osmosis (RO)

or Distillation processes that include multistage flash evaporation (MSF),
multiple effect distillation (MED), and vapor compression (VC). See YUAN ZHOU &

RICHARD S.J. TOL, EVALUATING THE COSTS OF DESALINATION AND WATER

TRANSPORT,

WATER RESOURCES RESEARCH, VOL. 41, available at http://www.unihamburg.de/Wiss

/FB/15/Sustainability/wrrdesalt.pdf (discussing the variety of desalting

technologies). The cost-efficiency of these technologies vary with specific site

characteristics. Accordingly, the cost per unit depends on size and location of

the desalination plant and is highly linked to the price of electricity.

"Larger plant capacity reduces the unit cost of water due to economies of scale.

Lower energy costs and longer plant period reduce unit product water cost." Id.

The data on desalination costs indicate that per unit cost has decreased since

the EPA first promulgated the UIC program in 1980. The average cost of

desalinating high TDS concentrations through RO has fallen from $3.70 per m3 in

1979 to about $1.33 per m3 in 2001. For the MSF process, the cost has gone down

from $3.04 m3 in 1979 to $.66 m3 in 2001. As for the ME process, the cost has

also decreased from $3.56 m3 in 1979 to $1.21 m3 in 2001. Lastly, the average

unit cost of VC has gone down from $3.72 m3 in 1979 to $1.50 m3 in 2001.[FN15] See

RESEARCH UNIT SUSTAINABILITY AND GLOBAL CHANGE, HAMBURG UNIVERSITY

AND CENTRE

FOR MARINE AND ATMOSPHERIC SCIENCE, available at

http://www.unihamburg.de/Wiss/FB/15/Sustainability/Models.htm cited in YUAN ZHOU

& TOL. at 4.

[FN15] Unit costs are given in terms of 1995 US dollars. See YUAN ZHOU & TOL,

supra, at 4.

For EPA to meet SDWA’s goal of ensuring that not only all current, but also all

reasonably expected, sources of drinking water are protected from GS, EPA must

update the 10,000 mg/L reference to reflect the "reasonable expectations" of

today based on the current state and foreseeable further advancement of

desalination technology.[FN16]

[FN16] Going forward, EPA should consider revising the definition of USDWs on a

rolling basis to prevent the TDS standard from becoming outdated and the

resulting endangerment of viable sources of drinking water by GS. In this way,

EPA will comply with its Congressional mandate to prevent endangerment of USDWs.

In addition, ELPC and ETIP note that the proposed regulation excludes from

protection aquifers and wells that likely would not be sufficient to supply

water to public water systems [FN17] but that are used as a supply of water for

smaller, private systems. At a minimum, EPA should require that owners of small

wells be consulted and included in the planning and permitting process for GS

wells and that provision be made to provide them with an alternative drinking

water source if necessary.

[FN17] "The term ‘public water system’ means a system for the provision to the

public of piped water for human consumption, if such system has at least fifteen

service connections or regularly serves at least twenty-five individuals." 42

U.S.C. § 300F(4).
Response: EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. Specifically, the Director must consider whether alternative

injection sites are available; community needs, demands, and supply from drinking water resources;

planned needs, potential and/or future use of USDWs and non-USDWs in the area; and a plan for

securing alternative resources or treating USDW formation waters in the event of contamination

related to the Class VI injection activity. 

EPA is not changing the USDW definition; changing the definition of a USDW is outside the scope

of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as required under the

SDWA, by establishing regulations to ensure the safe injection of CO2 for long-term storage. For

additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Andy Horn Letter ID: 0196

Commenter Organization: Colorado Ground Water Association (CGWA) Comment ID: 23923

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 1240

1.1.1.3 Suggested changes/edits to rule language; 1610 1.3.1 Risks to USDWs 

Comment: Issue 3. The proposed regulation currently defines USDWs as zones that contain 

groundwater with a total dissolved solids (TDS) concentration of less than 

10,000 mg/L. This limit should be revised to consider geologic strata with water 

containing higher TDS concentrations, because these zones may be economic in the 

future. 

The technology for treating high TDS water for use in water supply is improving 

rapidly, and these high TDS aquifer zones may be needed in the future. In areas 

with limited water resources water providers are beginning to turn to 

groundwater sources containing in excess of 10,000 mg/L TDS (Sengebush 2008). 

It is already conceivable that in the near future sources with up to 

approximately 20,000 mg/L TDS will be considered viable as water treatment 

technology advances making such water sources economical. To protect 

groundwater resources which may be economical in the foreseeable future the rule 

should evaluate the potential that currently marginal groundwater sources will 

be usable. The repository zones should be limited to strata containing very high 

TDS concentrations that siting studies and public input indicate are not likely 

to be useable in the future, as use of a zone for CO2 sequestration will likely 

preclude recovery and use of the groundwater resource in the future. 

Sengebush, R. M. 2008, INTERA, Inc. Deep Brackish Water Considered for New 

Mexico Development. Southwest Hydrology, March/April 2008, p. 8. Available from 

http://www.swhydro.arizona.edu/archive/V7_N2/dept-ontheground.pdf. 

Response: The Agency acknowledges the commenter’s concerns about water resources and future

water resource availability. However, modifying the definition of a USDW is outside the scope of

the GS rulemaking. USDWs are defined as aquifers currently being used as sources of drinking

water or those capable of supplying a public water system, with a total dissolved solids (TDS)
content of 10,000 milligrams per liter or less, as specified in §144.3. 

The primary goal of the UIC Program under the SDWA is to protect USDWs from endangerment in

order to ensure a reliable supply of drinking water for the American public. The GS rule, as part of

the UIC program regulations implementing the SDWA, continues the program’s mandate of

ensuring the protection of USDWs. EPA expects that the tailored permitting, siting, construction,

operation, monitoring, and post-injection site care requirements in the GS rule will prevent leakage

from injection formations and protect USDWs.

EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. Specifically, the Director must consider whether alternative

injection sites are available; community needs, demands, and supply from drinking water resources;

planned needs, potential and/or future use of USDWs and non-USDWs in the area; and a plan for

securing alternative resources or treating USDW formation waters in the event of contamination

related to the Class VI injection activity. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24625

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 2046

1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ dividing line between Class

II and Class VI (seeking comment) 

Comment: Rule Provision: 144.6 and 146.5 

Anadarko Petroleum Corporation (APC) Comments: (b) Class II. Wells which inject 

fluids:.... 

(4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC

SEQUESTRATION IS 

OCCURRING DURING OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR

NATURAL GAS 

PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE THAN INSIGNIFICANT

FUTURE 

PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION

AND (II) 

OPERATING PRESSURES ARE NO HIGHER THAN REASONABLY NECESSARY TO

PRODUCE SUCH 

VOLUMES OR RATES; AND 

(5) FOR GEOLOGIC SEQUESTRATION IN SUBSURFACE GEOLOGIC FORMATIONS IN

WHICH 

EXTRACTION OF HYDROCARBONS HAS OCCURRED, IS OCCURRING OR IS

REASONABLY EXPECTED 

TO OCCUR AND WHERE THE CRITERIA OF PARAGRAPH (B)(4) ARE NOT MET. 
(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon 

dioxide STREAMS. beneath the lowermost formation containing a USDW WELLS 

WHERE GEOLOGIC SEQUESTRATION OF CO2 STREAMS OCCURS DURING OR IN

CONNECTION WITH 

EOR OR EGR ARE REGULATED UNDER CLASS II. 

Rationale: The changes to (b) and (f) are to recognize that EOR can have storage 

component, which is consistent with EPA’s intent as expressed in the preamble 

and API’s October 27th meeting with EPA. It is widely recognized that CO2 based 

EOR can provide a significant early opportunity for carbon storage. As EPA 

correctly recognizes, CO2 EOR operations can have a significant storage 

component through capillary trapping or other mechanisms. 

Additionally, there should not be a blanket prohibition concerning injection 

above USDW’s or at specific depths. This is especially true given the 

possibility of changes in the definition of a USDW to include formations greater 

than 10,000 parts per million Total Dissolved Solids. This requirement is not 

necessary for the protection of USDWs and would remove a vast number of viable 

formations from consideration. Industry has shown that it can operate CO2 

injection wells in an EOR context without endangering USDWs that are located 

below the injection zone. An excellent example is the Salt Creek EOR project in 

Wyoming, which has a USDW below the injection zone. Moreover, under the proposed 

rule, there are other measures that would provide real assurance of formation 

integrity and require operators to demonstrate that their project will not 

endanger USDWs, making the lowermost USDW restriction unnecessary. 

Response: EPA did not make the suggested edits. EPA believes that the nature and risks of CO2

injection for the primary purpose of long-term storage pose different risks than injection for the

primary purpose of ER, and has developed new Class VI regulations to address these unique risks.

For example, the volume of CO2 anticipated to be injected for long-term storage is significantly

greater than for ER. Reservoir pressure conditions will also be different, with Class VI injection

operations involving large volumes of CO2 and likely having higher pressures within their storage

formations than Class II ER projects. EPA also recognizes that a by-product of ER activities is that a

certain percentage of the CO2 is trapped in the receiving formation.

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

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

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

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

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

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

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

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

allowing for site-specific flexibility.

Regarding injection into basalts, coal seams, and salt domes, EPA clarifies that the GS rule does not

preclude injection of CO2 into any non-USDW formation types. The purpose of the GS rule is to

ensure protection of USDWs from endangerment, and the rule requires that owners or operators

demonstrate that wells are sited in suitable systems with geologic formations to receive and confine

injected CO2, as required at §146.83 of the GS rule. The Class VI siting, well construction and
operation, monitoring and testing, and post-injection site care and site closure requirements are

designed to ensure that injected CO2 remains within the target formation. If an owner or operator

can demonstrate to the Director's satisfaction that GS in coal seams, basalts, salt domes, or shales

can be accomplished in a manner that protects USDWs and meets all of the requirements of the GS

rule, the project may be permitted as a Class VI well.

EPA acknowledges that there may be unknown risks associated with GS, particularly regarding GS

into formations such as coal seams, basalts, and salt domes, which have been the subject of limited

experimental projects in the past. EPA anticipates that in the short-term, GS into these types of

formations will continue to be experimental (i.e., to test GS technologies and collect data), and will

likely be permitted as Class V experimental technology wells subject to UIC Program Guidance #83.

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies.

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs. The final GS rule at §146.95 establishes a

process by which owners or operators can seek a waiver of the Class VI injection depth

requirements. The waiver approach requires the submission of extensive, site-specific information

(in conjunction with the permit application submittal) to demonstrate that injection of CO2 into a

formation that is above or between USDWs can be done in a manner that is protective of USDWs.

The requirements are designed to ensure the owner or operator, the Director, and the Regional

Administrator consider, on a site-specific basis, the implications, benefits, and challenges associated

with GS and ensuring water availability and USDW protection.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24635

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions; 4324

2.4.4.1.2 Comments opposed to requiring injection below the lowermost USDW 

Comment: Rule Provision: 146.81(d) [Definition - Geologic sequestration] 

Anadarko Petroleum Corporation (APC) Comments: Geologic sequestration project 

means an injection well or wells used to emplace a carbon dioxide stream 

beneath the lowermost formation containing a USDW INTO AN INJECTION ZONE 

EXCLUSIVELY FOR THE PURPOSE OF GEOLOGIC SEQUESTRATION. It includes the 

subsurface three-dimensional extent of the carbon dioxide plume, associated 

pressure front, and displaced brine, as well as the surface area above that 

delineated region. 

Rationale: There should not be a blanket prohibition concerning injection above 

USDW’s or at specific depths. This requirement is not necessary for the 

protection of USDWs and would remove a vast number of viable formations from 

consideration. Industry has shown that it can operate CO2 injection wells in an 

EOR context without endangering USDWs that are located below the injection zone. 

An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

measures that would provide real assurance of formation integrity and require 
operators to demonstrate that their project will not endanger USDWs, making the 

lowermost USDW restriction unnecessary. 

Response: EPA has revised the definition of a geologic sequestration project to account for the new

requirements to include “wells used for geologic sequestration of carbon dioxide that have been

granted a waiver of the injection depth requirements pursuant to requirements at §146.95.”

Commenter Name: Talib Syed Letter ID: 0537

Comment ID: 21474

Other EPA Comment Codes and Descriptions: 4344 2.4.4.2.2 Comments opposed to setting a

minimum injection depth 

Comment: Another item that I would like to bring to you know, to be considered is the 

depth of the lower most USDW. Yes in an ideal world, you want to have your 

injection zone below your lower most USDW, but what happens if you have USDW say 

at 20,000 feet? Nobody is using that USDW for practical purposes. You are not 

going to go and drill a water well 20,000 feet deep in order to supply a 

community, but at the same time it meets the criteria of less than 10,000 TDS. 

So there should be some flexibility on a case by case basis. Either if it is 

economically not feasible or it is technologically not feasible just as we have 

an aquifer exemption process or you know, for the Class II program. But I do 

prefer as a starting point that you use a zone that is you know, deeper than 

your lower most USDW, but not in every instance as mandatory requirement. 

Response: EPA is not changing the USDW definition; changing the definition of a USDW is

outside the scope of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as

required under the SDWA, by establishing regulations to ensure the safe injection of CO2 for longterm storage.

EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. Specifically, the Director must consider whether alternative

injection sites are available; community needs, demands, and supply from drinking water resources;

planned needs, potential and/or future use of USDWs and non-USDWs in the area; and a plan for

securing alternative resources or treating USDW formation waters in the event of contamination

related to the Class VI injection activity. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Comment Code: 4410 2.4.4.3.1 Comments in favor of allowing injection above/between USDWs in

certain circumstances 

Individual Comments

Commenter Name: Gerald C. Blount Letter ID: 0107
Comment ID: 21941

Comment: As a concerned practicing geoscientist I believe it is reasonable to 

regulate the geologic storage of CO2 by creating a new well class (Class VI) 

within the Underground Injection Control (UIC) program and it is necessary to 

protect underground drinking water sources. However, it may not be appropriate 

to categorically limit storage to formations with water salinity greater than 

10,000 parts per million. 

Another option should be available in the rule that considers other factors that 

may preclude the use of the aquifer as a source of drinking water or nullify 

threats to aquifers containing potable water. The USEPA has typically afforded 

this type of flexibility with technical documentation and deliberation. Prior to 

finalization of this rule it would be very simple and prudent to provide for 

another technical path within the process that would not limit technical 

strategies for carbon dioxide storage. 

If geologic storage of carbon dioxide is limited to formations with water 

salinities greater than 10,000 parts per million it is likely that there will be 

insufficient storage that is economically viable. Greenhouse gases are an 

immediate threat, EPA should regulate but not limit solutions that are 

technically viable, or increase costs when it is not necessary. Inflated storage 

costs will only cause delay. Global warming is far too great a threat to the 

human health and the environment to categorically limit potential CO2 storage 

sites. 

Response: EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. Specifically, the Director must consider whether alternative

injection sites are available; community needs, demands, and supply from drinking water resources;

planned needs, potential and/or future use of USDWs and non-USDWs in the area; and a plan for

securing alternative resources or treating USDW formation waters in the event of contamination

related to the Class VI injection activity. 

EPA is not changing the USDW definition; changing the definition of a USDW is outside the scope

of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as required under the

SDWA, by establishing regulations to ensure the safe injection of CO2 for long-term storage. For

additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Karl R. Moor Letter ID: 0109

Commenter Organization: Southern Company, on behalf of Edison Electric

Institute (EEI)

Comment ID:

22008

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW 

Comment: Similarly, the regulations should be sufficiently flexible to allow operators of 

geologic storage facilities, as well as operators of enhanced oil recovery or 

enhanced gas recovery projects converting their operations to geologic carbon 

storage facilities, to site these projects above underground sources of drinking 
water, if they can show there is unlikely to be harm to USDW. The proposed 

regulations make this nearly impossible since they would restrict injection for 

long-term storage to formations that are below the lowermost underground source 

of drinking water. Enhanced oil recovery and enhanced gas recovery facilities 

have been injecting carbon dioxide into formations above underground sources of 

drinking water for more than 30 years without migration or leakage incidents. 

Rather than reject these types of projects as potential geologic carbon storage 

sites by rule, EPA should permit the owners and operators of these kinds of 

projects to make their case based on the specific characteristics of each site. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach and

aquifer exemptions for Class VI wells, please see the final rule and preamble, as well as EPA's

responses to comments on the Notice of Data Availability and Request for Comment.

While the Agency acknowledges the experience gained by the oil and gas industry and other

injection activities, EPA identified unique challenges posed by large-scale GS including large

injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the

potential presence of impurities in captured CO2, and its mobility within subsurface geologic

formations that warrant the tailored approach in the GS rule. Furthermore, the Agency believes that

wells that inject into non-USDW formations above and between USDWs presents additional

challenges that warrant additional requirements.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22578

Other EPA Comment Codes and Descriptions: 4322 2.4.4.1.1 Comments in favor of requiring

injection below the lowermost USDW 

Comment: Preamble Questions: The location and proximity of other formations to USDWs may 

preclude their use for GS. EPA seeks comment on prohibiting injection into such 

formations if they are above the lowermost USDW. EPA Notice 54. 

NGWA Response: NGWA supports the general prohibition against injections above 
the lowermost USDW. An exemption process should be available to review and 

consider those specific situations where injection cannot be done, or is being 

proposed not to be done, below the lowermost USDW 

Response: EPA agrees that protecting USDWs from endangerment must be a top priority. The

Agency believes that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. 

The waiver approach requires the submission of extensive, site-specific information (in conjunction

with the permit application submission) to demonstrate that injection of CO2 into a non-USDW that

is above or between USDWs can be done in a manner that is protective of USDWs. It also

establishes procedures for public notice of a waiver application and for Director-Regional

Administrator communication and requirements specifying information that owners or operators

must submit, and Directors must consider, in consultation with PWSS Directors.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22585

Other EPA Comment Codes and Descriptions: 4322 2.4.4.1.1 Comments in favor of requiring

injection below the lowermost USDW 

Comment: Preamble Questions: EPA is soliciting comment on whether CO2 injection should be 

allowed into an injection zone above the lowermost USDW, when the Director 

determines that geologic conditions (e.g., thousands of feet of intervening 

formations between the injection zone and the overlying and/or underlying USDWs) 

exist that will prevent fluid movement into adjacent USDWs. EPA Notice 93. 

NGWA Response: NGWA supports the general prohibition against injections above 

the lowermost USDW. An exemption process should be available to review and 

consider those specific situations where injection cannot be done, or is being 

proposed not to be done, below the lowermost USDW 

Proposed Rule: 144.6(f) 

Comment: NGWA supports the general prohibition against injections above the 

lowermost USDW. An exemption process should be made available to review and 

consider those specific situations where injection cannot be done, or is being 

proposed not to be done, below the lowermost USDW. 

Rationale: NGWA understands that there may be portions of the country that will 

not have adequate storage zones below the lowermost USDW. In these areas, the 

Association believes that storage above the lowermost USDW may be allowed on a 

site specific basis based on director discretion assuming that all other 

conditions are met. 

Response: As described above, the final GS rule at §146.95 establishes a process by which owners

or operators can seek a waiver of the Class VI injection depth requirements for injection into non-
USDW formations above and/or between USDWs. The waiver approach requires the submission of

extensive, site-specific information to demonstrate that injection of CO2 into a non-USDW that is

above or between USDWs can be done in a manner that is protective of USDWs.

Commenter Name: Patrick Nugent Letter ID: 0143

Commenter Organization: Texas Pipeline Association (TPA) Comment ID: 23143

Comment: underground source of drinking water ("USDW"). Rather, a performance-based 

approach should be taken, in which the focus is on the containment qualities of 

the injection interval and on the overall geological environment, not simply on 

whether the reservoir is above or below the lowermost USDWs. TPA would note that 

carbon dioxide has been injected above the lowermost USDWs for decades without 

incident in connection with enhanced oil and gas recovery efforts in Texas. 

Imposition of an inflexible requirement that injection only occur below the 

lowermost USDW would unduly hinder the use of geologic sequestration technology, 

and it would be particularly inappropriate in instances where an injection site 

was situated above a USDW but there was a great distance between the injection 

site and the USDW and the characteristics of the intervening space prevented 

migration between the site and the USDW. EPA's focus should be on the particular 

physical characteristics that are presented, including distance and physical 

characteristics of the intervening space such as discussed above, as well as the 

containment qualities of the injection site being proposed. A site-specific 

approach would increase the use and thus the effectiveness of geologic 

sequestration technology. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

The waiver approach requires the submission of extensive, site-specific information (in conjunction

with the permit application submission) to demonstrate that injection of CO2 into a non-USDW that

is above or between USDWs can be done in a manner that is protective of USDWs. The

requirements are designed to ensure that the owner or operator, the Director, and the Regional

Administrator consider, on a site specific basis, the implications, benefits, and challenges associated

with GS and ensuring water availability and USDW protection. 

It establishes: 1) requirements specifying information that owners or operators must submit, and

Directors must consider, in consultation with PWSS Directors; 2) procedures for public notice of a

waiver application and for Director-Regional Administrator communication; 3) the waiver issuance

process; and, 4) additional requirements that apply to owners or operators of Class VI wells granted

a waiver of the injection depth requirements to ensure USDW protection above and below the

injection zone. EPA believes that these requirements will ensure USDW protection while providing

flexibility to UIC program Directors and owners or operators who undertake CO2 injection for GS.

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.
Commenter Name: Richard Driggans Letter ID: 0145

Commenter Organization: Tennessee Valley Authority Comment ID: 23157

Other EPA Comment Codes and Descriptions: 4322 2.4.4.1.1 Comments in favor of requiring

injection below the lowermost USDW 

Comment: sources by avoiding unnecessary siting and operational risks. Once experience 

is gained with the long-term behavior and geologic containment of CO2, injection 

depths above the lowermost USDW may be considered appropriate on a site-specific 

basis (e.g., where storage depth would be sufficient for maintaining CO2 in a 

supercritical state and separate from USDWs). 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

The waiver approach requires the submission of extensive, site-specific information (in conjunction

with the permit application submission) to demonstrate that injection of CO2 into a non-USDW that

is above or between USDWs can be done in a manner that is protective of USDWs. The

requirements are designed to ensure that the owner or operator, the Director, and the Regional

Administrator consider, on a site specific basis, the implications, benefits, and challenges associated

with GS and ensuring water availability and USDW protection. 

It establishes: 1) requirements specifying information that owners or operators must submit, and

Directors must consider, in consultation with PWSS Directors; 2) procedures for public notice of a

waiver application and for Director-Regional Administrator communication; 3) the waiver issuance

process; and, 4) additional requirements that apply to owners or operators of Class VI wells granted

a waiver of the injection depth requirements to ensure USDW protection above and below the

injection zone. EPA believes that these requirements will ensure USDW protection while providing

flexibility to UIC program Directors and owners or operators who undertake CO2 injection for GS.

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: James Dooley Letter ID: 0156

Commenter Organization: Joint Global Change Research Institute, Pacific

Northwest National Laboratory

Comment ID:

22625

Comment: On the Appropriateness of Allowing CO2 Storage above a USDW 

It seems that the overriding principle should be does the proposed Class VI rule 

help protect the wellbeing of humans and the health of the environment. Framing 

the issue in this way makes it clear that there is an explicit tradeoff being 

made about the use of USDWs for CO2 storage or the use of water bearing bodies 

that have more than 10,000 TDS but are shallower than another formation which 

has waters with less than 10,000 TDS. This calls for a flexible and site or 

region specific approach as opposed to an arbitrary criterion like "thousands of 

feet between the injection zone and overlying and underlying USDWs" - (page 

43512) If there are adequate caprocks above and below the "water bearing bodies 

that have more than 10,000 TDS but are shallower than another formation which 
has waters with less than 10,000 TDS" that should be a key (and explicitly noted 

in the final Class VI rule) criterion for deciding whether to allow a formation 

to be used for CO2 storage. 

The USEPA, as a whole, and not just the Office of Water that administers the UIC 

program, will likely need to create a transparent methodology for deciding 

whether it is better to use some specific deep saline-water bearing formations 

(total dissolved solids exceeding 10,000 mg/L) as repositories for anthropogenic 

CO2 or not. This is a complex decision that goes beyond the confines of the 

SDWA as one would not only need to consider the potential human uses for these 

waters (e.g., as a potential source of potable water via desalinization) or as a 

CO2 storage formation. This methodology should also take into account whether 

there are other potential large scale and economic means of reducing CO2 

emissions that could be employed to offset potential emissions and whether there 

are other bodies of water that could be treated to provide a more economical 

source of potable water. The methodology should be broader and more meaningful 

than simply asserting that either CO2 is injected into a given formation or it 

is vented to the atmosphere. The calculus here is more complex and nuanced. 

The USEPA should also explain what authority it has (or needs to be given) to 

ensure that any future wells (oil, gas, water, injection) that drill through a 

water bearing formation with greater than 10,000 TDS which has previously been 

used for CO2 storage are built to withstand the higher pressures and acidity of 

these formations without becoming pathways for the migration of previously 

stored CO2 out of the target storage formation. If the USEPA has no way of 

regulating the construction of production wells that penetrate through a water 

bearing formation that has been used for CO2 storage and if it believes that it 

will not be granted this authority, then this needs to bear on decisions to 

allow storage in formations that are shallower than a USDW. 

Lastly, it is important to note that my research group has performed preliminary 

analysis which sheds light on the extent to which this might be a significant 

issue. We have included a copy of this research along with our comments on the 

class VI rule. There are two points that are worth summarizing briefly here. 

o First, these are preliminary results. We stress that point because there is a 

lack of high quality and detailed data that would be needed to present a more 

rigorous analysis. This lack of high quality data is likely to persist for a 

very long time. 

o Second, it is clear to us from this analysis that the nation’s ability to cost 

effectively address climate change will not be significantly impacted regardless 

of whether the USEPA allows injection into formations that are shallower than 

the lowermost USDW or not, as the vast majority of the nation’s geologic CO2 

storage capacity is in formations that do not fall into this category (i.e., 

most DSF storage formations lie below the lowermost USDW). Having said that, it 

is clear that certain regions of the country might see their ability to deploy 

CCS constrained if the USEPA disallows the use of formations shallower than an 

USDW. While these impacts will be localized and region-specific it could be 

consequential for certain regions, firms, states and could narrow their 
portfolio of options for reducing CO2 emissions to the atmosphere. 

o This research of ours is documented in: 

CL Davidson, Dooley JJ, and RT Dahowski. 2008. "Assessing the Impacts of 

Future Demand for Saline Groundwater on Commercial Deployment of CCS in the 

United States." In the Proceedings of the 9th International Conference on 

Greenhouse Gas Technologies. PNNL-SA-63047, Pacific Northwest National 

Laboratory, Richland, WA. [SEE PDF TO VIEW THIS DOCUMENT.]

CL Davidson, JJ Dooley, SA Finne, RT Dahowski. February 2008. "How do salinity 

constraints impact the U.S. CO2 storage resource?" Joint Global Change Research 

Institute, Pacific Northwest National Laboratory. Richland, Washington. PNNLSA-58998. [SEE PDF TO VIEW THIS DOCUMENT.]

Response: EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. 

EPA adds that the GS rule requires that the Director, in evaluating whether a waiver is appropriate,

must consider planned needs, potential and/or future use of USDWs and non-USDWs in the area;

along with whether alternative injection sites are available; community needs, demands, and supply

from drinking water resources; and a plan for securing alternative resources or treating USDW

formation waters in the event of contamination related to the Class VI injection activity.

EPA clarifies that the purpose of the GS rule is to protect any formations that meet the definition of

a USDW where GS is to be employed. It is not the intent of the GS rule to evaluate the tradeoffs for

the use of deep saline formations. 

EPA is not changing the USDW definition; changing the definition of a USDW is outside the scope

of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as required under the

SDWA, by establishing regulations to ensure the safe injection of CO2 for long-term storage. For

additional information on the waiver approach and aquifer exemptions for Class VI wells, please see

the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: James Stine Letter ID: 0163

Commenter Organization: National Rural Electric Cooperative Association

(NRECA)

Comment ID:

21322

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW 

Comment: NRECA supports alternative approaches that would allow injection between and/or 

above the lowermost USDW, increasing capacity for CO2 GS, as long as Owners or 

Operators of Class VI wells can show that their CO2 GS operations will be 

protective of USDWs. Id. at 43512. This will be particularly important in areas 

of the country with deep USDWs, where an absolute requirement that Class VI 

wells be constructed beneath the lowermost USDW could render the program 
impractical. Id. NRECA also supports this alternative approach in areas where 

the Director determines -- or the Owner or Operator can show -- that geologic 

conditions would prevent fluid movement into adjacent USDWs. Id. For similar 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. It establishes: 1) requirements specifying

information that owners or operators must submit, and Directors must consider, in consultation with

PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements that

apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements

to ensure USDW protection above and below the injection zone. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24238

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 

EPA Preamble Question: 23. EPA is aware that the proposed requirement of 

injecting CO2 below the lowermost USDW may preclude injection into certain 

targeted geologic formations, which may be storage sites currently under 

consideration for GS. As a result, the Agency is considering and requesting 

comment on alternative approaches that would allow injection between and/or 

above the lowermost USDW, and thus potentially allow for more areas to be 

available for GS while preventing USDW endangerment. EPA Notice 43512. 

API Response: Injection above the lowest USDW should be allowed but the operator 

must demonstrate confinement above and below the injection formation. Retaining 

the restriction would remove a significant number of viable formations from 

consideration. Industry has shown that it can operate CO2 injection wells in an 

EOR context without endangering USDWs that are located below the injection zone. 

An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW 

below the injection zone. Moreover, under the proposed rule, there are other 

measures that would provide real assurance of formation integrity and require 

operators to demonstrate that their project will not endanger USDWs, making the 
lowermost USDW restriction unnecessary. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24239

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 

EPA Preamble Question: 24. EPA is soliciting comment on whether CO2 injection 

should be allowed into an injection zone above the lowermost USDW, when the 

Director determines that geologic conditions (e.g., thousands of feet of 

intervening formations between the injection zone and the overlying and/or 

underlying USDWs) exist that will prevent fluid movement into adjacent USDWs. 

EPA Notice 43512. 

API Response: See response to #23. CO2 injection zones should be selected based 

upon site specific evaluation of performance based criteria. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs.

Commenter Name: James Rower Letter ID: 0173

Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23481

Other EPA Comment Codes and Descriptions: 2200 1.6.4 Other formation types; 4430 2.4.4.3.3

Injection into coal seams above USDWs (seeking comment) 

Comment: of USDWs and meet other applicable conditions for Class VI CO2GS wells. As a 

result, USWAG believes that the Final Rule should not contain a blanket 

prohibition on injection of CO2 into coal seams (whether above or below the 

lowermost USDW) or into other formations such as basalts, salt domes, or shales. 

73 Fed. Reg. at 43503. If it can be demonstrated that the injection of CO2 into 

such sites is protective of USDWs, then such activities should remain available 

options under the Class VI UIC program. 

Response: The final GS rule does not preclude injection into any non-USDW formation type

provided owners or operators can demonstrate that GS can be performed in a manner that protects

USDWs from endangerment as required under today’s rulemaking. The Agency acknowledges that

GS into basalts, coal seams, salt domes, and shales will likely have limited application, or that

owners or operators seeking Class VI permits for injection into these formations may not be able to

meet the final GS requirements or demonstrate protection of USDWs. 

The purpose of the GS rule is to ensure protection of USDWs, and the rule includes requirements to

ensure that the geologic formations are adequate to receive and confine injected CO2, at §146.83.
The siting, well construction, operational, and other requirements in the GS rule are designed to

ensure that injected CO2 remains within the target formation. 

EPA acknowledges that there may be risks associated with GS, particularly regarding GS into

basalts, which have been the subject of limited experimental projects in the past. EPA anticipates

that in the short-term, GS into basalts, coal seams, salt domes, and shales will continue to be

experimental in nature (i.e., if they are to test GS technologies and collect data), and will likely be

permitted as Class V experimental technology wells and be subject to UIC Program Guidance #83.

EPA will continue to review data on early GS projects, including those in such formations, to

determine whether the appropriate amount and types of information and documentation are required

and being collected. EPA plans, every six years, to collect and review data on GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

EPA clarifies that the final rule requires that injection for GS be into non-USDWs below the

lowermost USDW; however, owners or operators may apply for a waiver from this requirement, as

described in §146.95. For more information, see the discussion of waivers in the preamble to the

final rule.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23819

Comment: F. GEOLOGIC SEQUESTRATION OF CO2 NEED NOT BE, IN EVERY INSTAKCE,

BENEATH THE 

LOWERMOST FORMATION CONTAINING A USDW 

Geologic sequestration of CO2 need not be, in every instance, beneath the 

lowermost formation containing a USDW, as is the case with Class I wells. Such a 

requirement likely would preclude injection into certain targeted geologic 

formations, which may include storage sites currently under consideration for 

GS. The Director should be given discretion, but to act in accordance with 

guidelines, to allow injection above or between USDWs in specific geological 

settings where the depth of the USDW would preclude GS and where there are 

thousands (or only hundreds) of feet of rock strata between the injection zone 

and the underlying or overlying USDW. This could in many instances open up more 

areas for CO2 storage without endangering USDWs. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation
types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

EPA clarifies that all decisions regarding injection depth waivers will be at the Director's discretion

and based on site-specific information. EPA is developing guidance on the injection depth waiver

process. The guidance describes the recommended approach an owner or operator may follow when

submitting a waiver application, processing waiver applications by the UIC and PWSS Program

Directors, and additional processes that may apply to projects that have been issued waivers. This

guidance will be available on EPA’s website at

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

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23859

Comment: Directors should have discretion to allow injection above or between USDWs in 

specific geological settings where going below the lowermost USDW would make GS 

impractical, as well as where there are appropriate strata between the injection 

zone and the underlying or overlying USDW. Such Director discretion, however, 

should be limited or based on measurable factors or criteria. The CCS Alliance 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs.

Determinations about the appropriateness of a waiver would be made by the Director, based on

evaluation of site-specific conditions.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25194

Comment: V. As a result, the Agency is considering and requesting comment on alternative 

approaches that would allow injection between and/or above the lowermost USDW, 

and thus potentially allow for more areas to be available for GS while 

preventing USDW endangerment. 

NYSDEC-DMN Response: While not a likelihood in New York State due to typical 

depths to lowermost USDWs, NYSDEC-DMN believes there should not be any blanket 

prohibition against injection into any potentially approvable geologic zone, 

even if it is above the lowermost USDW. There may be circumstances where this is 

appropriate and safe. The decision to permit a project should be made on a sitespecific basis and evaluation. 
Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. 

Determinations about the appropriateness of a waiver would be made by the Director, based on

evaluation of site-specific conditions. For additional information on the waiver approach and aquifer

exemptions for Class VI wells, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25195

Comment: W. In summary, EPA is soliciting comment on whether CO2 injection should be 

allowed into an injection zone above the lowermost USDW, when the Director 

determines that geologic conditions (e.g., thousands of feet of intervening 

formations between the injection zone and the overlying and/or underlying USDWs) 

exist that will prevent fluid movement into adjacent USDWs. 

NYSDEC-DMN Response: Injection criteria and the decision to permit a project 

should be made on a site-specific basis and evaluation. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs, where

approved by the Director, based on evaluation of site-specific conditions.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24530

Comment: Rule Provisions or Federal Register Cite: 144.6(f), 146.5, 146.81 

EPA Preamble Question: 23. EPA is aware that the proposal to limit CO2 injection 

to reservoirs below the lowermost USDW may preclude injection into certain 
geologic formations currently under consideration for GS. As a result, the 

Agency is considering and requesting comment on alternative approaches that 

would allow injection between and/or above the lowermost USDW, thus potentially 

allowing more areas to be available for GS while preventing USDW endangerment. 

EPA Notice 43512. 

CSC Response: Injection above the lowest USDW should be allowed as long as the 

operator can demonstrate confinement above and below the injection formation. 

Retaining the proposed restriction would remove a significant number of viable 

formations from consideration. It has been shown that CO2 injection wells can be 

operated in an EOR context without endangering USDWs that are located below the 

injection zone. An excellent example is the Salt Creek EOR project in Wyoming, 

which has a USDW below the injection zone. Moreover, under the proposed rule, 

there are other measures that would provide real assurance of formation 

integrity and require operators to demonstrate that their project will not 

endanger USDWs, making the lowermost USDW restriction unnecessary. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24531

Comment: Rule Provisions or Federal Register Cite: 144.6(f), 146.5, 146.81 

EPA Preamble Question: 24. EPA is soliciting comment on whether CO2 injection 

should be allowed into an injection zone above the lowermost USDW, when the 

Director determines that geologic conditions (e.g., thousands of feet of 

intervening formations between the injection zone and the overlying and/or 

underlying USDWs) exist that will prevent fluid movement into adjacent USDWs. 

EPA Notice 43512. 

CSC Response: See response to Question 23. CO2 injection zones should be 

selected based upon site specific evaluation of performance based criteria. 

"Thousands of feet of intervening formations" should not be necessary as long as 

it can be demonstrated that USDWs will be protected. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs.

Commenter Name: Paul Pike Letter ID: 0198

Commenter Organization: Ameren Corporation Comment ID: 23950

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW; 4460 2.4.4.4.1 Comments in favor of allowing aquifer
exemptions in certain circumstances 

Comment: INJECTION WELL OPERATING REQUIREMENTS 

Ameren supports allowing injection between and/or above the lowermost USDW, 

provided that the Class VI wells can be shown that their operations will be 

protective of USDWs. 73 Fed. Reg. at 43512. This could be particularly 

important in areas of the country with deep USDWs, where an absolute requirement 

that Class VI wells be constructed beneath the lowermost USDW could render the 

program impractical. We also support this approach in areas where it can be 

shown that geologic conditions would prevent fluid movement into adjacent USDWs. 

Id. Therefore, we oppose an absolute prohibition on use of exempt aquifers for 

Class VI injection; again use of exempt aquifers could be permitted where the 

specific aquifer exemption criteria are satisfied. Id. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24593

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 

EPA Rule Issue: 23. EPA is aware that the proposed requirement of injecting CO2 

below the lowermost USDW may preclude injection into certain targeted geologic 

formations, which may be storage sites currently under consideration for GS. As 

a result, the Agency is considering and requesting comment on alternative 

approaches that would allow injection between and/or above the lowermost USDW, 

and thus potentially allow for more areas to be available for GS while 

preventing USDW endangerment. EPA Notice 43512. 

Anadarko Petroleum Corporation (APC) Response: Injection above the lowest USDW 

should be allowed but the operator must demonstrate confinement above and below 
the injection formation. Retaining the restriction would remove a vast number of 

viable formations from consideration. Industry has shown that it can operate CO2 

injection wells in an EOR context without endangering USDWs that are located 

below the injection zone. An excellent example is the Salt Creek EOR project in 

Wyoming, which has a USDW below the injection zone. Moreover, under the proposed 

rule, there are other measures that would provide assurance regarding formation 

integrity and require operators to demonstrate that their project will not 

ndanger USDWs, making the lowermost USDW restriction unnecessary. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs, as long as appropriate

protections are in place. The final GS rule at §146.95 establishes a process by which owners or

operators can seek a waiver of the Class VI injection depth requirements for injection into nonUSDW formations above and/or between USDWs. The waiver approach requires the submission of

extensive, site-specific information (in conjunction with the permit application submission) to

demonstrate that injection of CO2 into a non-USDW that is above or between USDWs can be done

in a manner that is protective of USDWs. The requirements are designed to ensure that the owner or

operator, the Director, and the Regional Administrator consider, on a site specific basis, the

implications, benefits, and challenges associated with GS and ensuring water availability and USDW

protection. For additional information on the waiver approach, please see the final rule and preamble,

as well as EPA's responses to comments on the Notice of Data Availability and Request for

Comment.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24594

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 

EPA Rule Issue: 24. EPA is soliciting comment on whether CO2 injection should be 

allowed into an injection zone above the lowermost USDW, when the Director 

determines that geologic conditions (e.g., thousands of feet of intervening 

formations between the injection zone and the overlying and/or underlying USDWs) 

exist that will prevent fluid movement into adjacent USDWs. EPA Notice 43512. 

Anadarko Petroleum Corporation (APC) Response: See above response to EPA Notice 

43512. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs.

Commenter Name: John Corra Letter ID: 0205

Commenter Organization: Wyoming Department of Environmental Quality

(DEQ)

Comment ID:

22193

Comment: 1. Prohibiting CO2 injection into formations if they are above the lowermost 

USDW: 

a. We believe it's imperative that the Director be allowed discretion to allow 
injection above or between USDWs in specific geologic settings Where the depth 

of the USDWs may preclude geologic sequestration, make Geologic Sequestration 

(GS) technically challenging, or significantly limit CO2 storage capacity." Such 

approval by the Director would allow injection between USDWs (and thereby 

allowing injection above the lowermost USDW) in circumstances in which it can be 

demonstrated that USDWs would not be endangered. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Determinations about the appropriateness of

a waiver would be made by the Director, based on evaluation of site-specific conditions. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach for

Class VI wells, please see the final rule and preamble, as well as EPA's responses to comments on

the Notice of Data Availability and Request for Comment.

Commenter Name: Steven B. Corneli Letter ID: 0234

Commenter Organization: NRG Energy, Inc. Comment ID: 23161

Comment: Injection Zones for Geologic Sequestration (GS) 

The proposed rule limits GS to only those geologic formations that are below the 

lowermost underground source of drinking water (USDW). Prohibiting injection 

between and/or above the lowermost USDW would exclude GS in many potential 

storage reservoirs throughout the US that could be utilized for injection while 

still ensuring protection of USDWs. The petroleum industry has demonstrated that 

they can operate CO2 injection wells for EOR/EGR while preventing USDW 

endangerment. We believe protection of valuable drinking water sources could be 

accomplished through proper site selection and characterization. NRG recommends 

using science based techniques to demonstrate that geologic conditions exist 

that will prevent CO2 migration to USDWs. Under these circumstances, the 

lowermost USDW restriction would be unnecessary. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Determinations about the appropriateness of
a waiver would be made by the Director, based on evaluation of site-specific conditions.

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Abbie Krebsbach Letter ID: 0235

Commenter Organization: Montana-Dakota Utilities Co. Comment ID: 23182

Comment: be extremely unlikely to occur. For example, simply limiting CO2 injection to 

only beneath the lowermost formation containing Underground Sources of Drinking 

Water (USDW) is unwarranted. The suitability of the receiving formation and the 

project's general protectiveness of USDW are already required to be evaluated as 

a part of each GS permitting exercise in the proposed rule, and may prove that 

upper formations are appropriate for GS of CO2. 

Montana-Dakota believes that the properties of CO2, while unique in some 

respects, do not require or warrant such stringent treatment. Plainly adopting a 

requirement for CO2 GS, such as used for hazardous waste, would be likely to 

create the misperception that CO2 injection wells are analogous to hazardous 

waste injection wells and thus carry analogous risks. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The waiver approach requires the

submission of extensive, site-specific information (in conjunction with the permit application

submission) to demonstrate that injection of CO2 into a non-USDW that is above or between

USDWs can be done in a manner that is protective of USDWs. The requirements are designed to

ensure that the owner or operator, the Director, and the Regional Administrator consider, on a sitespecific basis, the implications, benefits, and challenges associated with GS and ensuring water

availability and USDW protection. 

EPA believes that the additional procedures for public notice of a waiver application and for

Director-Regional Administrator communication at §146.95 will improve public confidence in and

acceptance of GS projects operating under injection depth waivers. EPA clarifies that, due to the

unique nature of the injection depth waiver process and in an effort to ensure national consistency

and application of the requirements, the requirement at §146.95(d) indicates that the Regional

Administrator makes the final determination regarding waiver issuance following an evaluation of all

site-specific information, public notice, and recommendations from the UIC Director. For additional
information on the waiver approach, please see the final rule and preamble, as well as EPA's

responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23245

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW 

Comment: 23. EPA is aware that the proposed requirement of injecting CO2 below the 

lowermost USDW may preclude injection into certain targeted geologic formations, 

which may be storage sites currently under consideration for GS. As a result, 

the Agency is considering and requesting comment on alternative approaches that 

would allow injection between and/or above the lowermost USDW, and thus 

potentially allow for more areas to be available for GS while preventing USDW 

endangerment. EPA Notice 43512. 

Injection into a formation above the lowermost USDW should be allowed. As 

commented earlier, if injection above the lowermost USDW is not allowed it would 

eliminate a vast number of potential sequestration zones. Enhanced recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are 

available may severely limit sequestration options. These situations are best 

handled locally where other regional geologic factors can be considered. 

Demonstration that the upper and lower confining zones are adequate to prevent 

migration should be sufficient. The fact that the carbon dioxide plume is 

buoyant will protect any deeper USDW. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

Additionally, the final GS rule does not categorically preclude or prohibit injection into any type of

formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach For

additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment., please
see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23246

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW 

Comment: 24. EPA is soliciting comment on whether CO2 injection should be allowed into an 

injection zone above the lowermost USDW, when the Director determines that 

geologic conditions (e.g., thousands of feet of intervening formations between 

the injection zone and the overlying and/or underlying USDWs) exist that will 

prevent fluid movement into adjacent USDWs. EPA Notice 43512. 

Injection into a formation above the lowermost USDW should be allowed. As 

commented earlier, if injection above the lowermost USDW is not allowed it would 

eliminate a vast number of potential sequestration zones. Enhanced recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are 

available may severely limit sequestration options. These situations are best 

handled locally where other regional geologic factors can be considered. 

Demonstration that the upper and lower confining zones are adequate to prevent 

migration should be sufficient. The fact that the carbon dioxide plume is 

buoyant will protect any deeper USDW. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95

establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23276

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW 

Comment: 144.6 Class VI wells are to be limited to injection beneath the lowermost 

formation containing a USDW. This arbitrary exclusion would eliminate a vast 

number of potential sequestration zones. Enhanced oil and gas recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are 

available may unnecessarily limit sequestration options. These situations are 

best handled locally where all the pertinent regional geologic factors can be 

considered. The buoyancy of carbon dioxide suggests this in an unnecessary 

restriction since it would move injectate away from the USDWs below the 

sequestration zone. 

Response: As described above, EPA acknowledges that there are limited circumstances where

injection above the lowermost USDW can be performed in a manner that protects USDWs from

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95
establishes a process by which owners or operators can seek a waiver of the Class VI injection depth

requirements for injection into non-USDW formations above and/or between USDWs.

Commenter Name: Kurt Waltzer Letter ID: 0250

Commenter Organization: Clean Air Task Force Comment ID: 22298

Comment: We believe that GS sites located above lowermost USDWs may or may not present 

more types of risk than sites located below lowermost USDWs, but that in any 

event the consequences of leakage from sites above USDWs are likely to be more 

significant in the event that leakage occurs. At the same time, we recognize 

that there many potentially excellent sequestration sites above USDWs and that 

in some areas these may be the only sites available. We believe the rule should 

authorize GS sites above lowermost USDWs only if such sites meet requirements 

that go beyond what is mandatory for other sites. The following additional 

conditions would need to be satisfied: 

• confirmation that there is a confining zone underlying the entire base of the 

injection zone; 

• mandatory monitoring for changes in groundwater chemistry above the upper 

confining zone and below the lower confining zone; and 

• prior to permit issuance, and as a condition of permit issuance, completion of 

regional hydrogeologic studies that are conducted with sufficient accuracy to 

simulate regional hydrologic flows and demonstrate that USDWs would not be 

endangered if injected or formation fluids were to move beyond either the higher 

or the lower confining zone. 

Response: EPA agrees that there are limited circumstances where injection above the lowermost

USDW can be performed in a manner that protects USDWs from endangerment, as long as

appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

It establishes requirements specifying information that owners or operators must submit, and

Directors must consider (including the presence of confining zones above and below the injection

zone and detailed hydrologic evaluation of the proposed site), in consultation with PWSS Directors.

Owners or operators of Class VI wells granted a waiver of the injection depth requirements are

subject to additional requirements (e.g., ground water monitoring above and below the injection

zone) to ensure USDW protection above and below the injection zone.

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please
see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: William Herz Letter ID: 0266

Commenter Organization: The Fertilizer Institute Comment ID: 22881

Comment: Depth of CO2 injection 

EPA is soliciting comment on whether CO2 injection should be allowed into an 

injection zone above the lowermost USDW,when the Director determines that 

geologic conditions (e.g.,thousands of feet of intervening formations between the 

injection zone and the overlying and/or underlying USDWs) exist that will prevent 

fluid movement into adjacent USDWs. EPA is also requesting comments on whether 

aquifer exemptions should be allowed for the purpose of Class VI injection, 

and under what conditions should such aquifer exemptions be approved. Finally, 

EPA seeks comment on whether the Agency should set a minimum injection depth 

requirement for CO2 GS, rather than require that such injection take place below 

the lowermost USDW(73Fed. Reg. 43,512). 

TFI agrees with the alternative under consideration allowing for the Director's 

discretion in allowing injection above or between USDWs in specific geologic 

settings where the depth of the USDWs may preclude GS, make GS technically 

challenging, or significantly limit CO2 storage capacity in permit applications 

in which it is demonstrated that USDWswouldnot be endangered (73 Fed. Reg. 

43,512). A provision for the "Director's discretion" should be fully delineated 

in the final rule. This provision should allow the Director to determine whether 

the confining system is "of sufficient regional thickness and lateral extent to 

contain the entire CO2 plume and associated pressure front under the confining 

system following the plume's maximum lateral expansion (73 Fed. Reg. 43,505)." 

As EPA states later in the proposed rule,"[i]f the trapping mechanism is 

sufficiently protective, the injected CO2 should be contained regardless of its 

phase (73 Fed. Reg. 43,511)." TFI believes that aquifers associated with Class VI 

injection should be able to be reclassified as exempt aquifers under Part 144.7. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

Additionally, the final GS rule does not categorically preclude or prohibit injection into any type of

formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when
appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on aquifer exemptions for Class

VI wells, please see the final rule and preamble, as well as EPA's responses to comments on the

Notice of Data Availability and Request for Comment.

Commenter Name: Kevin Frederick Letter ID: 0525

Commenter Organization: Wyoming Department of Environmental Quality Comment ID: 21402

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW 

Comment: There are a few areas which we do not agree with EPA's proposed approach. 

Especially prohibiting injection into formations if they are above the lower 

most USDW. We believe it is imperative that the director be allowed discretion 

to allow injection above or between USDW's in specific geologic settings where 

the depth of the USDW's preclude geologic sequestration, make GS technically 

challenging or significantly limits storage capacity. Such approval by the 

director would allow injection between USDW's and thereby allow injection above 

the lower most USDW. In most circumstances it may be demonstrated that the 

USDW's would not be in danger. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. Additionally, the final GS rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: George Peridas Letter ID: 0534

Commenter Organization: Natural Resources Defense Council (NRDC) Comment ID: 21457

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW 

Comment: Now on the technical issues, the ones I would like to mention briefly without 
going into detail; I will defer to the comments about, is the definition of the 

area of review. The definition and treatment of a fault in the subsurface, I 

think I will echo some previous comments on whether to inject above or below the 

lowest USDW. The definition of a USDW might change. The TDS level in the future 

and that is crucial to policy decisions, but we will have to think very 

carefully of, but I think there are good examples of safe CO2 injection that are 

above the lowest USDW. I am willing to make sure that the emphasis is on having 

the adequate confinement systems and confining layers that protect USDW's 

whether they are above or below. 

Response: EPA recognizes that there is increasing demand for water resources and that technology

improvements may make high TDS aquifers viable drinking water sources. EPA believes these

potential resources should be considered when injection depth waivers are sought. Therefore, the

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether an

injection depth waiver is appropriate. Specifically, the Director must consider whether alternative

injection sites are available; community needs, demands, and supply from drinking water resources;

planned needs, potential and/or future use of USDWs and non-USDWs in the area; and a plan for

securing alternative resources or treating USDW formation waters in the event of contamination

related to the Class VI injection activity.

EPA is not changing the USDW definition; changing the definition of a USDW is outside the scope

of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as required under the

SDWA, by establishing regulations to ensure the safe injection of CO2 for long-term storage. 

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Comment Code: 4420 2.4.4.3.2 Comments opposing injection above/between USDWs in all cases 

Individual Comments

Commenter Name: Randy Joseph Letter ID: 0240

Commenter Organization: Western Organization of Resource Councils Comment ID: 23219

Comment: Water: One alternative under consideration is a provision for Director's 

discretion to allow injection above or between USDWs in specific geologic 

settings where the depth of the USDWs may preclude GS, make GS technically 

challenging, or significantly limit CO2 storage capacity. Such approval by the 

Director would allow injection between USDWs (and thereby allowing injection 

above the lowermost USDW) in circumstances in which it may be demonstrated that 

USDWs would not be endangered. An example where such injection may be 

appropriate presents itself in areas such as the Williston and Powder River 

Basins in Wyoming, North Dakota, and South Dakota, where receiving formations 

(formations with large CO2 storage capacity) for GS have been identified above 

the lowermost USDW and where there may be thousands of feet of rock strata 

between the injection zone and the overlying and underlying USDWs. In these 

cases, injection above or between USDWs may be appropriate, however, the Agency 

currently lacks data to demonstrate that such practices are or are not 
protective of USDWs. 

EPA is aware that the proposed requirement of injecting CO2 below the lowermost 

USDW may preclude injection into certain targeted geologic formations, which may 

be storage sites currently under consideration for GS. These formations may 

include unmineable coal seams (those not being used for Class II enhanced coal 

bed methane production), zones in between or above USDWs, and other formations 

also under consideration. In areas of the country with very deep USDWs, the need 

to construct GS wells beneath them may render GS technically impractical. As a 

result, the Agency is considering and requesting comment on alternative 

approaches that would allow injection between and/or above the lowermost USDW, 

and thus potentially allow for more areas to be available for GS while 

preventing USDW endangerment. 

USDWs are potentially affected by CO2 storage underground, particularly if there 

is leakage to the surface or cross-contamination through seepage of CO2 into an 

aquifer. Drinking water supplies cannot be easily cleaned up or replaced once 

contaminated. Geologic sequestration should occur only in places where 

injections would not compromise the safety of the Underground Sources of 

Drinking Water. Because preventing contamination and protecting water is of 

paramount importance, we oppose allowing any injections between and/or above the 

lowermost Underground Sources of Drinking Water. If EPA plans to grant such 

discretion, we urge you to develop detailed criteria in the regulations as to 

under what conditions such discretion could be exercised and release it for 

public comment ahead of time. 

Response: EPA agrees that protecting USDWs from endangerment must be a top priority. The

Agency believes that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. It establishes: 1) requirements specifying information that owners or operators must

submit, and Directors must consider, in consultation with PWSS Directors; 2) procedures for public

notice of a waiver application and for Director-Regional Administrator communication; 3) the

waiver issuance process; and, 4) additional requirements that apply to owners or operators of Class

VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and

below the injection zone. The final rule also establishes limited circumstances under which

expansions of the areal extent of aquifer exemptions may be granted for owners or operators of

Class II EOR/EGR wells transitioning to Class VI injection for GS. Additionally, the rule does not

categorically preclude or prohibit injection into any type of formation. 

EPA believes that the requirements at §146.95 will ensure USDW protection while providing

flexibility to UIC Program Directors and owners or operators who undertake CO2 injection for GS.

The Agency believes this approach: 1) responds to concerns about local and regional geologic

storage capacity limitations imposed by the proposed injection depth requirements; 2) allows for a

more site-specific assessment of injection depth for GS projects; 3) accommodates injection into

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or
between USDWs when appropriate and where it can be demonstrated that USDWs will be protected;

and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to

addressing injection depth variability through a waiver process responds to concerns about future

drinking water resource availability and the need to ensure that high quality water remains available

in sufficient quantities to supply drinking water needs. For additional information on the waiver

approach, please see the final rule and preamble, as well as EPA's responses to comments on the

Notice of Data Availability and Request for Comment.

Comment Code: 4430 2.4.4.3.3 Injection into coal seams above USDWs (seeking comment) 

Individual Comments

Commenter Name: John Hanger Letter ID: 0130

Commenter Organization: Pennsylvania Dept. of Env. Protection Comment ID: 21518

Comment: -DEP and DCNR agree that EPA should preclude the injection of CO2 for long-term 

storage into coal seams where they are above the lowermost USDW. 

-There are safety issues associated with injecting CO2 below existing coal 

reserves. Uplifting pressure effects from injection below coal seams, or within 

deeper coal formations, may rupture flooded abandoned mines situated above 

active coal mines and will also drive coal bed methane upward into overlying 

active mines. There is also the safety issue of having an injection well(s) 

penetrate through coal before it is mined, which could be encountered during 

mining with devastating effects, both from injected CO2 release and from sparks 

from mining equipment encountering drill casing, and igniting coal bed methane. 

Pennsylvania regulates against this occurrence, with respect to oil and gas 

wells drilled through unmined coal formations, by the issuance of a pillar 

permit. The interaction of coal mines and wells is a major safety concern 

addressed by PA Chapter 78 Oil & Gas Wells. This regulation states that no 

permit will be issued for a well at a location that would, in the opinion of 

DEP, endanger the safety of persons working in a coal mine. Pennsylvania 

regulations do not address coal mine safety issues related to water wells or 

underground injection wells. 

-In drilling through an unmined coal formation resource or gas or oil reservoir 

formation, what area and distances from the injection drill path are considered 

safe for development? In Pennsylvania, when oil and gas wells are developed 

through a coal formation resource, a pillar permit is obtained which defines the 

area of safety within the undeveloped resource formation surrounding the drill 

path. 

Response: The final GS rule does not categorically preclude or prohibit injection into any type of

formation, including coal seams. Instead, the requirements are designed to ensure protection of

USDWs from endangerment through proper siting, well construction, operation, monitoring, and

PISC at all sites selected for GS. 

EPA recognizes that some types of formations, such as coal seams and basalts, are typically shallow
and above the lowermost USDW. EPA expects that most injection wells conducting GS in these

shallow formations will be permitted as Class VI wells and such wells will be issued waivers,

provided that their owners or operators can meet all of the requirements for an injection depth waiver

at §146.95 and demonstrate that such injection can be performed in a manner that protects USDWs,

as long as appropriate protections are in place. The Class V experimental technology well

classification, may, in some instances be an appropriate permitting alternative. This decision should

be informed through a discussion between the injection well owner or operator and the Director to

determine the purpose and proper design of the well.

EPA adds that all decisions regarding injection depth waivers are at the Director's discretion. If a

Director believes that injection depth waivers are not appropriate for a specific site or for a category

of formations within their state, the Director has the authority to not permit such injections.

EPA is developing guidance on the injection depth waiver process. The guidance describes the

recommended approach an owner or operator may follow when submitting a waiver application,

processing waiver applications by the UIC and PWSS Program Directors, and additional processes

that may apply to projects that have been issued waivers. This guidance will be available on EPA’s

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

For additional information on the waiver approach, please see the final rule and preamble, as well as

EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Commenter Name: James Dooley Letter ID: 0156

Commenter Organization: Joint Global Change Research Institute, Pacific

Northwest National Laboratory

Comment ID:

22626

Comment: On page 43503, the EPA requests comment on whether GS CO2 storage in coal seams 

which lie above a USDW should be categorically prohibited. In keeping with the 

discussion above, it seems that a more robust set of metrics and a broader 

framework should be employed rather than a blanket prohibition. If there is a 

suitable coal seam that is isolated above and below by strong caprocks and if 

EPA has the ability to influence / control how drilling through this formation 

in the future might occur then there’s no obvious reason to prohibit a Class VI 

application. It would be more rigorous and more in keeping with the spirit of 

the SDWA to establish a set of technical benchmarks that need to be satisfied 

rather than seemingly ruling certain GS applications out. This comment also 

applies to the proposed prohibition on injection into "Other Formations" (p. 

43503); rather than creating an inflexible prohibition USEPA should work to 

establish rigorous benchmarks and thresholds that would need to be satisfied to 

allow CO2 storage in these formations. If these benchmarks are difficult to 

satisfy because there is solid reasoning for creating higher thresholds, then 

that would have the same impact as a prohibition but still leave the door open 

for technological progress to make it feasible. 

Response: The final GS rule does not categorically preclude or prohibit injection into any type of

formation, including coal seams. Instead, the requirements are designed to ensure protection of

USDWs from endangerment through proper siting, well construction, operation, monitoring, and

PISC at all sites selected for GS. 

EPA recognizes that some types of formations, such as coal seams and basalts, are typically shallow

and above the lowermost USDW. EPA expects that most injection wells conducting GS in these
shallow formations will be permitted as Class VI wells and such wells will be issued waivers,

provided that their owners or operators can meet all of the requirements for an injection depth waiver

at §146.95 and demonstrate that such injection can be performed in a manner that protects USDWs,

as long as appropriate protections are in place. The Class V experimental technology well

classification, may, in some instances be an appropriate permitting alternative. This decision should

be informed through a discussion between the injection well owner or operator and the Director to

determine the purpose and proper design of the well.

For additional information on the waiver approach and aquifer exemptions for Class VI wells, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23413

Other EPA Comment Codes and Descriptions: 4320 2.4.4.1 Injection beneath the lowermost

formation containing a USDW 

Comment: Class VI CO2 GS wells. APPA offers no opinions on injection of CO2 into coal 

seams. APPA defers to the American Water Works Association regarding the 

questions pertaining to whether above or below the lowermost USDW. The EPA asked 

Response: EPA believes that there are limited circumstances where injection above the lowermost

USDW can be performed in a manner that protects USDWs from endangerment, as long as

appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing

injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24217

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 

EPA Preamble Question: 5. EPA is proposing to preclude the injection of CO2 for 

long-term storage into coal seams where they are above the lowermost USDW. EPA 

requests comment on this proposed prohibition. EPA Notice 43503. 

API Response: API opposes this restriction. Qualification of a formation for 
storage should be based on performance-based standards and site-specific 

considerations. 

Response: The final GS rule does not categorically preclude or prohibit injection into any type of

formation, including coal seams. Instead, the requirements are designed to ensure protection of

USDWs from endangerment through proper siting, well construction, operation, monitoring, and

PISC at all sites selected for GS. 

EPA recognizes that some types of formations, such as coal seams and basalts, are typically shallow

and above the lowermost USDW. EPA expects that most injection wells conducting GS in these

shallow formations will be permitted as Class VI wells and such wells will be issued waivers,

provided that their owners or operators can meet all of the requirements for an injection depth waiver

at §146.95 and demonstrate that such injection can be performed in a manner that protects USDWs,

as long as appropriate protections are in place. The Class V experimental technology well

classification may, in some instances, be an appropriate permitting alternative. This decision should

be informed through a discussion between the injection well owner or operator and the Director to

determine the purpose and proper design of the well.

For additional information on the waiver approach and aquifer exemptions for Class VI wells, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: James Rower Letter ID: 0173

Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23481

Other EPA Comment Codes and Descriptions: 2200 1.6.4 Other formation types; 4410 2.4.4.3.1

Comments in favor of allowing injection above/between USDWs in certain circumstances 

Comment: of USDWs and meet other applicable conditions for Class VI CO2GS wells. As a 

result, USWAG believes that the Final Rule should not contain a blanket 

prohibition on injection of CO2 into coal seams (whether above or below the 

lowermost USDW) or into other formations such as basalts, salt domes, or shales. 

73 Fed. Reg. at 43503. If it can be demonstrated that the injection of CO2 into 

such sites is protective of USDWs, then such activities should remain available 

options under the Class VI UIC program. 

Response: The final GS rule does not preclude injection into any non-USDW formation type

provided owners or operators can demonstrate that GS can be performed in a manner that protects

USDWs from endangerment as required under today’s rulemaking. The Agency acknowledges that

GS into basalts, coal seams, salt domes, and shales will likely have limited application, or that

owners or operators seeking Class VI permits for injection into these formations may not be able to

meet the final GS requirements or demonstrate protection of USDWs. 

The purpose of the GS rule is to ensure protection of USDWs, and the rule includes requirements to

ensure that the geologic formations are adequate to receive and confine injected CO2, at §146.83.

The siting, well construction, operational, and other requirements in the GS rule are designed to

ensure that injected CO2 remains within the target formation. 

EPA acknowledges that there may be risks associated with GS, particularly regarding GS into

basalts, which have been the subject of limited experimental projects in the past. EPA anticipates

that in the short-term, GS into basalts, coal seams, salt domes, and shales will continue to be
experimental in nature (i.e., if they are to test GS technologies and collect data), and will likely be

permitted as Class V experimental technology wells and be subject to UIC Program Guidance #83.

EPA will continue to review data on early GS projects, including those in such formations, to

determine whether the appropriate amount and types of information and documentation are required

and being collected. EPA plans, every six years, to collect and review data on GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

EPA clarifies that the final rule requires that injection for GS be into non-USDWs below the

lowermost USDW; however, owners or operators may apply for a waiver from this requirement, as

described in §146.95. For more information, see the discussion of waivers in the preamble to the

final rule.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24509

Comment: Rule Provisions or Federal Register Cite: 144.6(f), 146.5, 146.81 

EPA Preamble Question: 5. EPA is proposing to preclude the injection of CO2 for 

long-term storage into coal seams where they are above the lowermost USDW. EPA 

requests comment on this proposed prohibition. EPA Notice 43503. 

CSC Response: CSC opposes this restriction. Qualification of a formation for 

storage should be based on performance-based standards and site-specific 

considerations. Because we recommend allowing GS in formations that may be above 

the lowermost USDW, the rule should clearly provide that GS would only be 

allowed into an injection zone for which Director determines that geologic and 

other conditions exist that will prevent fluid movement that endangers USDWs 

above or below. 

There are significant differences in geology from one area of the country to 

another. Rather than impose an arbitrary limit based on the depth of the 

lowermost USDW or a specific minimum depth restriction, EPA should follow its 

stated objective and use a performance standard that is clearly spelled out and 

can be met with appropriate demonstrations of containment. 

Response: The final GS rule does not categorically preclude or prohibit injection into any type of

formation, including coal seams. Instead, the requirements are designed to ensure protection of

USDWs from endangerment through proper siting, well construction, operation, monitoring, and

PISC at all sites selected for GS. 

EPA recognizes that some types of formations, such as coal seams and basalts, are typically shallow

and above the lowermost USDW. EPA expects that most injection wells conducting GS in these

shallow formations will be permitted as Class VI wells and such wells will be issued waivers,

provided that their owners or operators can meet all of the requirements for an injection depth waiver

at §146.95 and demonstrate that such injection can be performed in a manner that protects USDWs,

as long as appropriate protections are in place. The Class V experimental technology well

classification, may, in some instances be an appropriate permitting alternative. This decision should

be informed through a discussion between the injection well owner or operator and the Director to

determine the purpose and proper design of the well.
For additional information on the waiver approach and aquifer exemptions for Class VI wells, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24572

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 

EPA Rule Issue: 5. EPA is proposing to preclude the injection of CO2 for longterm storage into coal seams where they are above the lowermost USDW. EPA 

requests comment on this proposed prohibition. EPA Notice 43503. 

Anadarko Petroleum Corporation (APC) Response: APC opposes this restriction. 

Qualification of a formation for storage should be based on performance-based 

standards and site-specific considerations. It is more important to recognize 

that for those first pilot projects the Class V experimental well regulations 

may be better suited. However, if the data can be shown that USDW protection can 

be achieved through proper confining units and reservoir trapping mechanisms, 

injection into coal seams above the lowermost USDW should be allowed. 

Response: The final GS rule does not categorically preclude or prohibit injection into any type of

formation, including coal seams. Instead, the requirements are designed to ensure protection of

USDWs from endangerment through proper siting, well construction, operation, monitoring, and

PISC at all sites selected for GS. 

EPA recognizes that some types of formations, such as coal seams and basalts, are typically shallow

and above the lowermost USDW. EPA expects that most injection wells conducting GS in these

shallow formations will be permitted as Class VI wells and such wells will be issued waivers,

provided that their owners or operators can meet all of the requirements for an injection depth waiver

at §146.95 and demonstrate that such injection can be performed in a manner that protects USDWs,

as long as appropriate protections are in place. The Class V experimental technology well

classification, may, in some instances be an appropriate permitting alternative. This decision should

be informed through a discussion between the injection well owner or operator and the Director to

determine the purpose and proper design of the well.

Regarding the suggestion to allow experimental GS wells to continue to operate under Class V, EPA

anticipates that some owners or operators will apply for Class V experimental technology permits for

injection into formations including shallow basalts, coal seams, salt caverns, and shales. These

formations may or may not be located above the lowermost USDW or between USDWs. To

facilitate experimental injection for GS and to increase understanding of injection into these

formation types, the Agency is amending the Class V experimental technology guidance. The

guidance will be available on EPA's web site at

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. EPA acknowledges that the Class

V experimental technology well sub-classification may be appropriate for these projects, provided

they are experimental in nature. EPA expects that, following the final GS rule, a limited number of

experimental injection projects testing GS technology will continue. EPA anticipates that these

projects will be small-scale and involve limited CO2 volumes. However, if these projects become

larger scale and are no longer experimental, they will need to be permitted as Class VI wells. The

construction, operation, or maintenance of any non-experimental Class V GS well is prohibited, at
§144.15.

For additional information on the waiver approach and aquifer exemptions for Class VI wells, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: John Corra Letter ID: 0205

Commenter Organization: Wyoming Department of Environmental Quality

(DEQ)

Comment ID:

22197

Comment: 3. Prohibiting the injection of CO2 for long-term storage into coal seams where 

they are above the lowermost USDW: 

a. We believe there are likely circumstances where injection into formations 

(including deep, unmineable coal seams) situated above the lowermost USDW may be 

practical and protective of overlying and underlying USDWs. 

Response: The final GS rule does not categorically preclude or prohibit injection into any type of

formation, including coal seams. Instead, the requirements are designed to ensure protection of

USDWs from endangerment through proper siting, well construction, operation, monitoring, and

PISC at all sites selected for GS. 

EPA recognizes that some types of formations, such as coal seams and basalts, are typically shallow

and above the lowermost USDW. EPA expects that most injection wells conducting GS in these

shallow formations will be permitted as Class VI wells and such wells will be issued waivers,

provided that their owners or operators can meet all of the requirements for an injection depth waiver

at §146.95 and demonstrate that such injection can be performed in a manner that protects USDWs,

as long as appropriate protections are in place. The Class V experimental technology well

classification, may, in some instances be an appropriate permitting alternative. This decision should

be informed through a discussion between the injection well owner or operator and the Director to

determine the purpose and proper design of the well.

For additional information on the waiver approach and aquifer exemptions for Class VI wells, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Christopher Murray Letter ID: 0207

Commenter Organization: Pacific Northwest National Laboratory Comment ID: 22448

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW; 4340 2.4.4.2 Minimum injection depth (seeking comment) 

Comment: Stratigraphic Restriction of Saline and Other Reservoirs to Below Lowermost USDW 

PROPOSED REGULATION FOR SALINE FORMATIONS 

p. 43494, c. 2 Saline formations: Deep and geographically extensive sedimentary 

rock layers saturated with waters or brines that have a high total dissolved 

solids (TDS) content (i.e., >10,000 mg/L TDS). 

p. 43505, c. 1 1. Proposed Geologic Siting Requirements Existing UIC 
requirements for siting injection wells include identification of geologic 

formations suitable to receive the injected fluids and confine them such that 

they are isolated below the lowermost USDWs, minimizing the potential for 

endangerment. 

p. 43502-43503, section Hon target geologic formations As with unmineable coal 

seams, EPA seeks comment on prohibiting injection into such formations [basalts, 

salt domes, and shales] if they are above the lowermost USDW. 

The EPA is soliciting comments on these issues: 

1. Whether CO2 injection should be allowed into an injection zone (saline 

sedimentary formations, unminable coal seam, basalt, salt caverns, shales, or 

other reservoirs) above the lowermost USDW, when the Director determines that 

geologic conditions exist that will prevent fluid movement into adjacent USDWs. 

2. Whether a designated USDW should be exempted to allow for GS, and under what 

conditions should these exemptions be approved. 

3. Whether all USDWs should be exempted below a CO2 injection receiving bed. 

4. Whether the EPA should set a minimum injection depth requirement for GS, 

rather than require that such injection take place below the lowermost USDW. 

DISCUSSION 

Three of the most important issues here are (a) the physical location of saline 

formations or other types of geologic reservoirs for GS, relative to USDWs; (b) 

under what circumstances the EPA should remove one or more water-bearing zones 

from the list of USDWs to allow injection; and (c) under what other conditions 

should the EPA allow injection above a USDW. 

In addition to injection into saline formations, EPA recognizes that basalt, 

unmineable coal seams, salt domes, abandoned mines, black shales and other types 

of reservoirs may be promising emerging targets. Basalts, in particular appear 

to have considerable potential for GS Research by PNNL and others indicates that 

extruded basalt flow tops and flow bases may have considerable potential for GS. 

Research by PNNL and others indicates that extruded basalt flow tops and flow 

bases may have regional, multi-gigaton capacity for CO2 storage. In addition, 

laboratory experiments suggest that regional, multi-gigaton capacity for CO2 

storage. mineralization of large volumes of CO2 may proceed within a few years 

of injection (McGrail et al, 2006). 

In the proposed rule, the new Class VI wells would be allowed to inject CO2 into 

basalts, deep saline reservoirs, and other potential reservoirs only when they 

are beneath the lowermost USDW. 

A USDW is defined by the EPA as "An aquifer or portion of an aquifer that 

supplies any public water system or that contains a sufficient quantity of 

ground water to supply a public water system, and currently supplies drinking 
water for human consumption, or that contains fewer than 10,000 mg/1 total 

dissolved solids and is not an exempted aquifer." This definition would include 

many non-potable aquifers that would be candidates for GS. 

The EPA's reliance on the standard definition of a USDW as being solely <10,000 

mg/L TDS is far too restrictive. In many states, this standard is not applied - 

all groundwaters are protected regardless of water quality. In at least one 

state GS operations would be permitted if removing anthropogenic CO2 is 

considered a greater public benefit than the loss of a marginal aquifer. 

The EPA is aware that restricting GS to a position below all EPA defined USDWs 

would severely limit GS in many areas. Under the current proposed rule, directors 

may grant injection into deep, marginal USDWs that directly overlie crystalline 

basement rock and/or unmineable coal seams. In addition to these exceptions, the 

EPA would consider allowing operation of GS wells where receiving formations are 

above the lowermost USDW only where there are thousands of feet between the 

injection zone and the overlying and underlying USDWs. 

REFERENCES 

McGrail, B. P., H. T. Schaef, A. M. Ho, Y. Chien, J. J. Dooley, and C. L. 

Davidson. 2006. Potential for Carbon Dioxide Sequestration in Flood Basalts, J. 

Geophys. Res. 111, B12201. 

Response: Regarding injection into basalts, coal seams, and salt domes, EPA clarifies that the GS

rule does not categorically preclude injection of CO2 into any non-USDW formation types. The

purpose of the GS rule is to ensure protection of USDWs from endangerment, and the rule requires

that owners or operators demonstrate that wells are sited in suitable systems with geologic

formations to receive and confine injected CO2, as required at §146.83 of the GS rule. The Class VI

siting, well construction and operation, monitoring and testing, and post-injection site care and site

closure requirements are designed to ensure that injected CO2 remains within the target formation. If

an owner or operator can demonstrate to the Director's satisfaction that GS in coal seams, basalts,

salt domes, or shales can be accomplished in a manner that protects USDWs and meets all of the

requirements of the GS rule, the project may be permitted as a Class VI well. 

EPA acknowledges that there may be unknown risks associated with GS, particularly regarding GS

into formations such as coal seams, basalts, and salt domes, which have been the subject of limited

experimental projects in the past. EPA anticipates that in the short-term, GS into these types of

formations will continue to be experimental (i.e., if they are to test GS technologies and collect data),

and will likely be permitted as Class V experimental technology wells and be subject to UIC

Program Guidance #83. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental

technology well classification to clarify permitting for Class V wells. This addendum will address

shifting of Class V experimental projects to full-scale GS projects and the future use of the Class V

experimental technology well subclass for research and testing of new GS technologies. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs. The final GS rule at §146.95 establishes a

process by which owners or operators can seek a waiver of the Class VI injection depth
requirements. The waiver approach requires the submission of extensive, site-specific information

(in conjunction with the permit application submittal) to demonstrate that injection of CO2 into a

formation that is above or between USDWs can be done in a manner that is protective of USDWs.

The requirements are designed to ensure the owner or operator, the Director, and the Regional

Administrator consider, on a site specific basis, the implications, benefits, and challenges associated

with GS and ensuring water availability and USDW protection.

EPA is not changing the USDW definition; changing the definition of a USDW is outside the scope

of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as required under the

SDWA, by establishing regulations to ensure the safe injection of CO2 for long-term storage. 

EPA believes that there is increasing demand for water resources and that technology improvements

may make high TDS aquifers viable drinking water sources. EPA believes these potential resources

should be considered when injection depth waivers are sought. Therefore, the final GS rule at

§146.95(b) requires the Director to consider these issues in determining whether an injection depth

waiver is appropriate. Specifically, the Director must consider whether alternative injection sites are

available; community needs, demands, and supply from drinking water resources; planned needs,

potential and/or future use of USDWs and non-USDWs in the area; and a plan for securing

alternative resources or treating USDW formation waters in the event of contamination related to the

Class VI injection activity.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23226

Other EPA Comment Codes and Descriptions: 2163 1.6.3.1 Comments in favor of injection into

unmineable coal seams 

Comment: 5. EPA is proposing to preclude the injection of CO2 for long-term storage into 

coal seams where they are above the lowermost USDW. EPA requests comment on 

this proposed prohibition. EPA Notice 43503. 

This arbitrary exclusion would eliminate a vast number of potential 

sequestration zones. Enhanced recovery operations above the lowermost USDW have 

been taking place for a very long time. Unmineable coals in North Dakota are 

found in high clay content glacial till which, if unfractured, serves as an 

excellent confining zone. Based upon carbon dioxide’s affinity to adhere to 

coals, it is unwise to arbitrarily eliminate a potentially large number of 

sequestration zones. Exclusion of these zones even in areas where other 

abundant supplies of freshwater are available may severely limit sequestration 

options. These situations are best handled locally where all of the pertinent 

regional geologic factors can be considered. 

Response: EPA acknowledges that site-suitability for GS is dependent on a number of factors and

that many formation types may be suitable for GS. The final GS rule does not preclude injection into

unmineable coal seams (or any formation type) provided owners or operators can demonstrate that

GS can be performed in a manner that protects USDWs from endangerment based on requirements

under today’s rulemaking. The Agency anticipates that in the near-term, most GS in unmineable coal

seams will continue to be experimental. Such projects may be permitted as Class V experimental

technology wells if they are of an experimental nature (i.e., to test GS technologies and collect data).

EPA will continue to review data on early GS projects, including those in unmineable coal seams, to
determine whether the appropriate amount and types of information and documentation are required

and being collected. EPA plans, every six years, to collect and review data on GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

EPA recognizes that GS in unmineable coal seams has been the subject of less research than saline

formations or depleted oil and gas reservoirs. However, EPA has examined select field projects

involving injection into unmineable coal seams, including the Pump Canyon Site, near Archuleta,

New Mexico. In the Notice of Data Availability and Request for Comment, EPA described research

at the Pump Canyon site where the Southwest Partnership is studying CO2 injection into deep,

unmineable coal seams and performing a "seal analysis" of the ability of the Kirtland Formation to

act as a barrier to the movement of CO2 or other reservoir fluids. EPA continues to follow this

project, recently completed projects, and ongoing GS projects injecting into unmineable coal seams.

Other coal seam injection projects are underway through the RCSPs in the Illinois Basin, Black

Warrior Basin, and Central Appalachian Basin.

EPA clarifies that the final rule requires that injection for GS be into non-USDWs below the

lowermost USDW; however, owners or operators may apply for a waiver from this requirement, as

described in §146.95. For more information, see the discussion of waivers in the preamble to the

final rule.

Comment Code: 4440 2.4.4.3.4 Injection into organic-rich shales above USDWs (seeking comment)

Individual Comments

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21761

Comment: (2) Organic-Rich Shales Are Primary Remaining Supply of Natural Gas 

EPA also states in the Preamble that organic-rich shales are potential 

reservoirs for geologic sequestration of CO2. However, these shales are also the 

single largest source of natural gas remaining in the United States, and will 

likewise help to ensure that low-carbon energy supplies are available to fuel 

the United States’s economy. EPA should include in its Preamble a clear 

statement that nothing in the Preamble and/or the Proposed Rule should be 

interpreted or inferred as a preference for the use of these organic-rich shales 

for geologic sequestration as opposed to natural gas production. Whether 

organic-rich shales are used for natural gas production or geologic 

sequestration should be a matter left to negotiations between private parties. 

Response: EPA clarifies that the GS rule does not address the use of any formation types or specific

formations for a particular activity (e.g., GS or natural gas production). Rather, the intent of the GS

rule is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from

endangerment.
Comment Code: 4450 2.4.4.4 Use of aquifer exemptions (seeking comment) 

Individual Comments

Commenter Name: Steven Pirner Letter ID: 0153

Commenter Organization: South Dakota Department of Environment and

Natural Resources

Comment ID:

22137

Comment: 2. To allow for additional flexibility, South Dakota recommends that aquifer 

exemptions be allowed for Class VI wells. 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Quinlan J. Shea Letter ID: 0177

Commenter Organization: Edison Electric Institute Comment ID: 23579

Comment: While EPA acknowledges that it has raised for consideration the possibility of 

aquifer exemptions or the use of discretion to allow injection above the 

lowermost USDW in a given case, such a procedure would only insert complexity 

into the process, with no corresponding increase in protection afforded to USDW, 

as compared to an approach under which the merits of a proposed receiving 

formation are considered in the context of a particular project as a default. 

Response: EPA believes that there are limited circumstances where aquifer exemptions for GS may

be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). 

EPA clarifies that aquifer exemption expansions are limited to Class II EOR/EGR wells transitioning

to Class VI injection for GS. The aquifer exemption requirements in the final rule provide flexibility

and afford owners or operators an opportunity to assess and select a suitable GS site while also

preserving USDWs (i.e., formations/aquifers afforded SDWA protection). Class VI owners or

operators granted expansions of existing Class II EOR/EGR aquifer exemptions for GS projects must

meet all of the tailored requirements for GS wells in the final GS rule.

The Agency clarifies that the aquifer exemption requirements and the injection depth waiver

requirements serve different purposes. Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule, including the requirements at §146.83 for site criteria. EPA believes

that, in most cases, the injection depth waiver is a more appropriate option than aquifer exemptions
for Class VI injection, and believes that aquifer exemption expansions for GS should be granted in

limited circumstances.

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Quinlan J. Shea Letter ID: 0177

Commenter Organization: Edison Electric Institute Comment ID: 23581

Comment: Should the Agency choose to impose any sort of limitation on receiving 

formations, whether as a default or as a discretionary provision, the ability to 

obtain an aquifer exemption should be considered an absolute necessity absent a 

potential threat to USDW. In particular, aquifer exemptions would be necessary 

to facilitate complete grandfathering of existing projects. However, there 

would also be broader needs for aquifer exemptions in order to ensure that 

otherwise viable projects can go forward. 

Response: As described above, the final GS rule allows for the expansion of the areal extent of

existing aquifer exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS

pursuant to requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions

of existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored

requirements for GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. If an owner or operator applies for a

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above

and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR

operations and Class VI operations are considered during the aquifer exemption application process

and the Class VI permitting process. These differences include the anticipated large CO2 injection

volumes associated with GS, the buoyant and mobile nature of the injectate, and its corrosivity in the

presence of water. The Agency believes that this process will encourage owners or operators and

Directors to consider the use of alternative formations for GS, including non-USDW formations

through the waiver process, prior to applying for or approving aquifer exemption expansions for

Class II EOR/EGR wells transitioning to Class VI GS operations.

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Christopher Murray Letter ID: 0207
Commenter Organization: Pacific Northwest National Laboratory Comment ID: 22449

Comment: As currently defined by the EPA, "aquifer exemptions" permanently remove a 

specified aquifer from protection as a USDW. Aquifer exemptions are currently 

granted for mineral or hydrocarbon exploration by Class III solution mining 

wells, or by Class II oil and gas related wells, when there is no reasonable 

expectation that the formation will be used as a drinking water supply. It is 

important to note that the EPA has not previously considered the purpose of 

creating additional capacity for the emplacement of fluids as sufficient cause 

for granting an exemption. Under the new rule, it would be possible for 

operators to apply to change the designation of some aquifers being used for 

Class II injection. These aquifers would need a new, separate exemption for GS. 

Response: The final rule allows for the expansion of the areal extent of existing aquifer exemptions

for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to requirements at

§§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing Class II

EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for GS

wells in the final GS rule. However, the final rule precludes the issuance of new aquifer exemptions

for Class VI GS wells; that is, aquifer exemptions will only be granted for projects that are

transitioning from Class II EOR/EGR wells to Class VI. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR

operations and Class VI operations are considered during the aquifer exemption application process

and the Class VI permitting process. These differences include the anticipated large CO2 injection

volumes associated with GS, the buoyant and mobile nature of the injectate, and its corrosivity in the

presence of water. The Agency believes that this process will encourage owners or operators and

Directors to consider the use of alternative formations for GS, including non-USDW formations

through the waiver process, prior to applying for or approving aquifer exemption expansions for

Class II EOR/EGR wells transitioning to Class VI GS operations.

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. If an owner or operator applies for a

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above

and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Stephen Owens Letter ID: 0286

Commenter Organization: Arizona Department of Environmental Quality Comment ID: 25299

Comment: The Arizona Department of Environmental Quality (ADEQ) has reviewed the 

referenced proposed EPA rule . ADEQ does not implement the Underground Injection 

Control (UIC) program in Arizona, rather, ADEQ implements a state authorized 

Aquifer Protection Permit (APP) program. ADEQ has worked closely and effectively 

with the EPA Region IX UIC program for many years to ensure consistency in 

approach to regulating discharges to Arizona's aquifers. ADEQ believes that the 

proposed rule contains appropriate provisions to regulate geologic sequestration 
of carbon dioxide via the national UIC program. In this comment, ADEQ wishes to 

emphasize the unique statutory and geologic issues related to carbon injection 

and sequestration in Arizona. 

While one of the EPA UIC program's criteria for exemption of aquifers is a 

concentration of 10,000 mg/L or more of total dissolved solids, Arizona has no 

similar exemption in current law. Arizona law classifies all aquifers for 

drinking water use (Arizona Revised Statutes § 49-224). In the past, the use of 

high-TDS groundwater for drinking in Arizona has not been necessary due to 

sufficient supplies of high-quality water resources. However, as the state's 

population has grown and potable water resources have become scarce, many 

Arizona water providers must now treat brackish groundwater to provide drinking 

water to their customers. ADEQ believes that the use of high-TDS groundwater in 

Arizona will only increase, and that saline aquifers represent potentially 

valuable water resources. 

The Region IX UIC program and the ADEQ APP program have historically cooperated 

on various projects, including injection wells and dry wells. The approach has 

been that EPA Region 9 would not issue a UIC permit if ADEQ could not issue an 

APP. ADEQ expects that these cooperative efforts between the two programs will 

continue, particularly regarding potential commercial scale geologic 

sequestration of carbon dioxide in deep saline aquifers in Arizona. The two 

permitting programs are now actively cooperating to permit a U.S. Department of 

Energy funded pilot sequestration test in northeastern Arizona. ADEQ looks 

forward to continued cooperation with EPA's UIC program. 

Response: EPA acknowledges the commenter's support of the proposed approach. The UIC

program's mission is the protection of all USDWs 

EPA believes that the creation of a new injection well class (VI) under the existing UIC Program is

necessary to enable the use of GS as a climate change mitigation technology in a manner that

protects USDWs from endangerment. The GS rule contains minimum technical criteria for the

permitting, geologic site characterization, AoR and corrective action, well construction, operation,

mechanical integrity testing, monitoring, financial responsibility, injection well plugging, postinjection site care, and site closure of GS wells, which will ensure that USDWs are protected from

endangerment. 

EPA believes that the UIC Program, under the authority of the SDWA, provides a strong framework

for regulating injection of CO2 for GS and adds that the GS regulation tailors the UIC requirements

to address the unique issues associated with large-scale GS including large injection volumes, the

relative buoyancy of CO2, its corrosivity in the presence of water, the potential presence of

impurities in captured CO2, and its mobility within subsurface geologic formations.

The Agency clarifies that, in States with primary enforcement responsibility for underground

injection wells, the decision to allow aquifer exemptions or the injection depth waivers at §146.95 is

at the discretion of the State pursuant to State statutes. If a State/UIC Director believes that aquifer

exemptions or injection depth waivers are not appropriate for their State, the Director has the

authority to not include those provisions in the State regulations.

For additional information on EPA's final approach to regulating GS, please see the final rule and
preamble.

Comment Code: 4460 2.4.4.4.1 Comments in favor of allowing aquifer exemptions in certain

circumstances 

Individual Comments

Commenter Name: James Dooley Letter ID: 0156

Commenter Organization: Joint Global Change Research Institute, Pacific

Northwest National Laboratory

Comment ID:

22641

Comment: It Is Appropriate to Require Class II Fields to be Recertified before Conversion 

to Class VI Fields Page 43512. It is appropriate for the USEPA to require a new 

aquifer exemption for a formerly Class II injection field if there is a desire 

to use that field for GS. EPA should retain this requirement in the final rule. 

Just because a formation was deemed appropriate for Class II activities, does 

not guarantee that it is suitable for GS and therefore EPA is right to ask for 

more fact finding and potentially remediation of artificial penetrations before 

allowing the formation to be exempted and used for GS. 

Response: EPA recognizes that there are limited circumstances where aquifer exemptions for GS

may be warranted, and the final GS rule allows for the expansion of the areal extent of existing

aquifer exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant

to requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of

existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored

requirements for GS wells in the final GS rule.

EPA agrees that Class II EOR/EGR owners or operators should reapply for exemptions before

transforming to Class VI status. If an owner or operator applies for a Class VI permit to inject CO2

into a previously exempted aquifer (non-USDW) that is located above and/or between USDWs, the

permit applicant must also apply for a waiver of the injection depth requirements pursuant to

§146.95 to ensure that if a waiver is granted, USDWs above and below the injection zone are

protected from endangerment. 

EPA clarifies that the final rule precludes the issuance of new aquifer exemptions for Class VI GS

wells; that is, aquifer exemptions will only be granted for projects that are transitioning from Class II

EOR/EGR wells to Class VI. 

EPA adds that any Class II well owner or operator seeking to inject CO2 for the purpose of GS

would need to have their well re-permitted as Class VI. The final Class VI regulations require that

any owner or operator injecting CO2 for the primary purpose of long term storage obtain a Class VI

permit with some special consideration for the fact that they are transitioning from a well not

originally designed to meet Class VI requirements. The Director has the authority to determine at

what point a Class VI permit is required for those projects that are transitioning from the primary

purpose of EOR to long term storage of CO2. The final regulation provides a set of technical factors

for the Director to evaluate in making this determination, at §144.19. EPA believes that this

approach provides sufficient protection of USDWs when there is an increased risk to USDWs as

compared to traditional Class II operations while allowing for site-specific flexibility. See the
preamble and final rule for additional information on EPA's approach transitioning of Class II wells

for GS.

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: James Stine Letter ID: 0163

Commenter Organization: National Rural Electric Cooperative Association

(NRECA)

Comment ID:

21323

Comment: reasons, NRECA opposes an absolute prohibition on use of exempt aquifers for 

Class VI injection; use of exempt aquifers should be permitted where the 

specific aquifer exemption criteria are satisfied. Id. 

Response: EPA recognizes that there are limited circumstances where aquifer exemptions for GS

may be warranted, and the final GS rule allows for the expansion of the areal extent of existing

aquifer exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant

to requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of

existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored

requirements for GS wells in the final GS rule.

EPA clarifies that the final rule precludes the issuance of new aquifer exemptions for Class VI GS

wells; that is, aquifer exemptions will only be granted for projects that are transitioning from Class II

EOR/EGR wells to Class VI. 

EPA adds that any Class II well owner or operator seeking to inject CO2 for the purpose of GS

would need to have their well re-permitted as Class VI. The final Class VI regulations require that

any owner or operator injecting CO2 for the primary purpose of long term storage obtain a Class VI

permit with some special consideration for the fact that they are transitioning from a well not

originally designed to meet Class VI requirements. The Director has the authority to determine at

what point a Class VI permit is required for those projects that are transitioning from the primary

purpose of EOR to long term storage of CO2. The final regulation provides a set of technical factors

for the Director to evaluate in making this determination, at §144.19. EPA believes that this

approach provides sufficient protection of USDWs when there is an increased risk to USDWs as

compared to traditional Class II operations while allowing for site-specific flexibility. See the

preamble and final rule for additional information on EPA's approach transitioning of Class II wells

for GS.

The Agency clarifies that the aquifer exemption requirements and the injection depth waiver

requirements serve different purposes. Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule, including the requirements at §146.83 for site criteria. EPA believes

that, in most cases, the injection depth waiver is a more appropriate option than aquifer exemptions

for Class VI injection, and believes that aquifer exemption expansions for GS should be granted in

limited circumstances.

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.
Commenter Name: Michael Mudd Letter ID: 0167

Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 22460

Comment: As currently defined by the EPA, "aquifer exemptions" permanently remove a 

specified aquifer from protection as a USDW. Aquifer exemptions are currently 

granted for mineral or hydrocarbon exploration by Class III solution mining 

wells, or by Class II oil and gas related wells, when there is no reasonable 

expectation that the formation will be used as a drinking water supply. It is 

important to note that the EPA has not previously considered the purpose of 

creating additional capacity for the emplacement of fluids as sufficient cause 

for granting an exemption. Under the new rule, it would be possible for 

operators to apply to change the designation of some aquifers being used for 

Class II injection. These aquifers would need a new, separate exemption for GS. 

Response: The final rule allows for the expansion of the areal extent of existing aquifer exemptions

for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to requirements at

§§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing Class II

EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for GS

wells in the final GS rule. However, the final rule precludes the issuance of new aquifer exemptions

for Class VI GS wells; that is, aquifer exemptions will only be granted for projects that are

transitioning from Class II EOR/EGR wells to Class VI. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR

operations and Class VI operations are considered during the aquifer exemption application process

and the Class VI permitting process. These differences include the anticipated large CO2 injection

volumes associated with GS, the buoyant and mobile nature of the injectate, and its corrosivity in the

presence of water. The Agency believes that this process will encourage owners or operators and

Directors to consider the use of alternative formations for GS, including non-USDW formations

through the waiver process, prior to applying for or approving aquifer exemption expansions for

Class II EOR/EGR wells transitioning to Class VI GS operations.

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. If an owner or operator applies for a

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above

and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24240

Comment: Rule Provisions: 73 FR 43512 

EPA Preamble Question: 25. EPA is also requesting comments on whether aquifer 

exemptions should be allowed for the purpose of Class VI injection, and under 

what conditions should such aquifer exemptions be approved. EPA Notice 43512. 

API Response: There should be no changes to the aquifer exemption requirements 
in the UIC program as they exist today. Each aquifer exemption should be 

considered on a case-specific basis. 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 

The Agency clarifies that the aquifer exemption requirements and the injection depth waiver

requirements serve different purposes. Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule, including the requirements at §146.83 for site criteria. EPA believes

that, in most cases, the injection depth waiver is a more appropriate option than aquifer exemptions

for Class VI injection, and believes that aquifer exemption expansions for GS should be granted in

limited circumstances.

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. If an owner or operator applies for a

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above

and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR

operations and Class VI operations are considered during the aquifer exemption application process

and the Class VI permitting process. These differences include the anticipated large CO2 injection

volumes associated with GS, the buoyant and mobile nature of the injectate, and its corrosivity in the

presence of water. The Agency believes that this process will encourage owners or operators and

Directors to consider the use of alternative formations for GS, including non-USDW formations

through the waiver process, prior to applying for or approving aquifer exemption expansions for

Class II EOR/EGR wells transitioning to Class VI GS operations. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: James Rower Letter ID: 0173

Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23495

Comment: conditions would prevent fluid movement into adjacent USDWs. Id. For similar 

reasons, USWAG opposes an absolute prohibition on use of exempt aquifers for 

Class VI injection; use of exempt aquifers should be permitted where the 

specific aquifer exemption criteria are satisfied. Id. 
Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 

The Agency clarifies that the aquifer exemption requirements and the injection depth waiver

requirements serve different purposes. Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule, including the requirements at §146.83 for site criteria. EPA believes

that, in most cases, the injection depth waiver is a more appropriate option than aquifer exemptions

for Class VI injection, and believes that aquifer exemption expansions for GS should be granted in

limited circumstances.

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. If an owner or operator applies for a

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above

and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR

operations and Class VI operations are considered during the aquifer exemption application process

and the Class VI permitting process. These differences include the anticipated large CO2 injection

volumes associated with GS, the buoyant and mobile nature of the injectate, and its corrosivity in the

presence of water. The Agency believes that this process will encourage owners or operators and

Directors to consider the use of alternative formations for GS, including non-USDW formations

through the waiver process, prior to applying for or approving aquifer exemption expansions for

Class II EOR/EGR wells transitioning to Class VI GS operations. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23860

Comment: should be limited or based on measurable factors or criteria. The CCS Alliance 

also agrees that Directors should be able to exempt all USDWs below the 

injection zone, pursuant to "aquifer exemptions." 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing
Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 

The Agency clarifies that the aquifer exemption requirements and the injection depth waiver

requirements serve different purposes. Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule, including the requirements at §146.83 for site criteria. EPA believes

that, in most cases, the injection depth waiver is a more appropriate option than aquifer exemptions

for Class VI injection, and believes that aquifer exemption expansions for GS should be granted in

limited circumstances.

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. If an owner or operator applies for a

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above

and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR

operations and Class VI operations are considered during the aquifer exemption application process

and the Class VI permitting process. These differences include the anticipated large CO2 injection

volumes associated with GS, the buoyant and mobile nature of the injectate, and its corrosivity in the

presence of water. The Agency believes that this process will encourage owners or operators and

Directors to consider the use of alternative formations for GS, including non-USDW formations

through the waiver process, prior to applying for or approving aquifer exemption expansions for

Class II EOR/EGR wells transitioning to Class VI GS operations. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25196

Comment: X. EPA is also requesting comments on whether aquifer exemptions should be 

allowed for the purpose of Class VI injection, and under what conditions should 

such aquifer exemptions be approved. 

NYSDEC-DMN Response: Aquifer exemptions under Class VI should be allowed on the 

same basis as for other classes. Each exemption should be considered on its own 

merits based on local geologic conditions and the likelihood of use of the zone 

for future public water supply. 

Response: EPA believes that there are limited circumstances where aquifer exemptions for GS may

be warranted. The final rule allows for the expansion of the areal extent of existing aquifer
exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 

All decisions regarding whether expansion of existing aquifer exemptions will be at the Director's

discretion and based on site-specific information. If an owner or operator applies for a Class VI

permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above and/or

between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24532

Comment: Rule Provisions or Federal Register Cite: 73 FR 43512 

EPA Preamble Question: 25. EPA is also requesting comments on whether aquifer 

exemptions should be allowed for the purpose of Class VI injection, and under 

what conditions should such aquifer exemptions be approved. EPA Notice 43512. 

CSC Response: At this time, we do not recommend any specific need for new 

aquifer exemption criteria created because the existing criteria are perceived 

to be sufficient to allow aquifer exemptions as needed for GS. Even without 

changes, the aquifer exemption requirements in the UIC program would allow 

operators to obtain appropriate exemptions for GS operations. In addition, there 

should be no requirement that sequestration be below the lowermost USDW. 

Unfortunately - as the preamble to the proposed rule notes - the aquifer 

exemption process has effectively been disabled because EPA has sometimes 

refused to consider aquifer exemption requests for non-injection formations. 73 

Fed. Reg. at 43512. Rather than preventing underground injection that "endangers 

drinking water sources" as the statute requires, this approach arbitrarily 

prevents injection that does not endanger any drinking water sources. This 

approach should be abandoned; instead, the aquifer exemption rules should be 

applied as written. 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.
However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 

EPA clarifies that all decisions regarding expansion of existing aquifer exemptions will be at the

Director's discretion and based on site-specific information. If an owner or operator applies for a

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above

and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Paul Pike Letter ID: 0198

Commenter Organization: Ameren Corporation Comment ID: 23950

Other EPA Comment Codes and Descriptions: 4324 2.4.4.1.2 Comments opposed to requiring

injection below the lowermost USDW; 4410 2.4.4.3.1 Comments in favor of allowing injection

above/between USDWs in certain circumstances 

Comment: INJECTION WELL OPERATING REQUIREMENTS 

Ameren supports allowing injection between and/or above the lowermost USDW, 

provided that the Class VI wells can be shown that their operations will be 

protective of USDWs. 73 Fed. Reg. at 43512. This could be particularly 

important in areas of the country with deep USDWs, where an absolute requirement 

that Class VI wells be constructed beneath the lowermost USDW could render the 

program impractical. We also support this approach in areas where it can be 

shown that geologic conditions would prevent fluid movement into adjacent USDWs. 

Id. Therefore, we oppose an absolute prohibition on use of exempt aquifers for 

Class VI injection; again use of exempt aquifers could be permitted where the 

specific aquifer exemption criteria are satisfied. Id. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, as long

as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which

owners or operators can seek a waiver of the Class VI injection depth requirements for injection into

non-USDW formations above and/or between USDWs. The final rule also establishes limited

circumstances under which expansions of the areal extent of aquifer exemptions may be granted for

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS.

EPA believes that these requirements will ensure USDW protection while providing flexibility to

UIC program Directors and owners or operators who undertake CO2 injection for GS. The Agency

believes this approach: 1) responds to concerns about local and regional geologic storage capacity

limitations imposed by the proposed injection depth requirements; 2) allows for a more site-specific

assessment of injection depth for GS projects; 3) accommodates injection into different formation

types; 4) allows for injection of CO2 for GS into non-USDWs above and/or between USDWs when

appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to

concerns about the use of aquifer exemptions for GS. Finally, EPA’s approach to addressing
injection depth variability through a waiver process responds to concerns about future drinking water

resource availability and the need to ensure that high quality water remains available in sufficient

quantities to supply drinking water needs. For additional information on the waiver approach, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24595

Comment: Rule Provisions: 73 FR 43512 

EPA Rule Issue: 25. EPA is also requesting comments on whether aquifer 

exemptions should be allowed for the purpose of Class VI injection, and under 

what conditions should such aquifer exemptions be approved. EPA Notice 43512. 

Anadarko Petroleum Corporation (APC) Response: There should be no changes to the 

aquifer exemption requirements in the UIC program as it exists today. Each 

aquifer exemption should be considered on a case-specific basis. However, there 

should also be no requirement that sequestration be below the lowest USDW (see 

comment to EPA Notice 43512 above). 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 

EPA clarifies that all decisions regarding expansion of existing aquifer exemptions will be at the

Director's discretion and based on site-specific information. If an owner or operator applies for a

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above

and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Chris M. Hobson Letter ID: 0201

Commenter Organization: Southern Company Comment ID: 22165

Comment: For similar reasons, Southern Company opposes an absolute prohibition on use of 

exempt aquifers for Class VI injection (including sole source aquifers); use of 

exempt aquifers should be permitted where the specific aquifer exemption 

criteria are satisfied. Id. The Final Rule should give Directors latitude to 

approve injection plans for a range of sites based on scientific data and 
technical demonstrations that the site will contain the injected CO2 streams, 

thereby preventing endangerment of USDWs. 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. If an owner or operator applies for a

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above

and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: John Corra Letter ID: 0205

Commenter Organization: Wyoming Department of Environmental Quality

(DEQ)

Comment ID:

22195

Other EPA Comment Codes and Descriptions: 4320 2.4.4.1 Injection beneath the lowermost

formation containing a USDW 

Comment: b. Furthermore, we support providing Directors the flexibility and discretion 

to: 

i. Exempt all USDWs below the injection zone (if necessary to meet a requirement 

that injection is only allowed beneath the deepest USDW). 

ii. Exempt aquifers for the purpose of CO2 injection in accordance with the 

requirements of 40 CFR 144.7. 

iii. Exempt aquifers for the purpose of CO2 injection in accordance with the 

requirements of 40 CFR 146.4. 

c. In the event that aquifer exemptions are not feasible, we urge the US EPA to 

allow CO2 injection into aquifers previously exempted for Class I and Class II 

injection operations, provided that the operator obtains a new aquifer exemption 

for the purpose of GS. 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer
exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. 

EPA adds that the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells.

Aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. Aquifer exemption expansions are limited to Class II EOR/EGR wells

transitioning to Class VI injection for GS. The aquifer exemption requirements in the final rule

provide flexibility and afford owners or operators an opportunity to assess and select a suitable GS

site while also preserving USDWs (i.e., formations/aquifers afforded SDWA protection). Class VI

owners or operators granted expansions of existing Class II EOR/EGR aquifer exemptions for GS

projects must meet all of the tailored requirements for GS wells in the final GS rule.

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Christopher Murray Letter ID: 0207

Commenter Organization: Pacific Northwest National Laboratory Comment ID: 22451

Comment: - The conditions for exemptions of aquifers should be clarified. Aquifer 

exemptions should be allowed for GS ("a receiving bed for Class VI wells") when 

it can be demonstrated that there is no reasonable expectation that the 

formation will be considered for a drinking water source, and when it can be 

demonstrated that CO2 is highly unlikely to migrate updip into a portion of the 

formation that may be considered for use as a USDW. 

- Blanket aquifer exemption of all USDWs below a GS zone is not needed if there 

is demonstration of a competent seal between the injection zone and the first 

underlying USDW. 

Response: EPA acknowledges that there are limited circumstances where injection above the

lowermost USDW can be performed in a manner that protects USDWs from endangerment, and the

final GS rule does not categorically preclude or prohibit injection into any type of formation. 

The final GS rule, at §146.95, establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The final rule also establishes limited circumstances under which expansions of

the areal extent of aquifer exemptions may be granted for owners or operators of Class II EOR/EGR

wells transitioning to Class VI injection for GS pursuant to requirements at §§146.4 and 144.7(d). 

The Agency clarifies that the aquifer exemption requirements and the injection depth waiver

requirements serve different purposes. Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule, including the requirements at §146.83 for site criteria. EPA believes

that, in most cases, the injection depth waiver is a more appropriate option than aquifer exemptions
for Class VI injection, and believes that aquifer exemption expansions for GS should be granted in

limited circumstances.

If an owner or operator applies for a Class VI permit to inject CO2 into a previously exempted

aquifer (non-USDW) that is located above and/or between USDWs, the permit applicant must also

apply for a waiver of the injection depth requirements pursuant to §146.95 to ensure that if a waiver

is granted, USDWs above and below the injection zone are protected from endangerment. 

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. EPA is developing guidance on the

injection depth waiver process. The guidance describes the recommended approach an owner or

operator may follow when submitting a waiver application, processing waiver applications by the

UIC and PWSS Program Directors, and additional processes that may apply to projects that have

been issued waivers. This guidance will be available on EPA’s website at

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

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23247

Comment: 25. EPA is also requesting comments on whether aquifer exemptions should be 

allowed for the purpose of Class VI injection, and under what conditions should 

such aquifer exemptions be approved. EPA Notice 43512. 

Aquifer exemptions should be allowed pursuant to existing requirements in other 

injection well classes. 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Robert F. Voorhees Letter ID: 0243

Commenter Organization: Underground Injection Technology Group (UIT

Group)

Comment ID:

23338

Comment: A. Aquifer Exemptions 
The Safe Drinking Water Act charged EPA with the responsibility to prevent 

underground injection that "endangers drinking water sources." 42 U.S.C. §300h. 

EPA has undertaken this mission with zeal and remarkable success. EPA’s 

aggressive regulatory scheme starts with a consciously overbroad definition of 

the range of aquifers to be protected. Indeed, EPA’s regulatory definition of 

"underground source of drinking water" (or "USDW") is not limited to aquifers 

that are or could reasonably be expected to serve as drinking water sources, but 

includes all aquifers capable of producing minimum amounts of water that contain 

less than 10,000 mg/l total dissolved solids. 40 C.F.R. §144.3. Recognizing 

the overbreadth of its basic "USDW" definition, EPA provided an "aquifer 

exemption" mechanism under which aquifers can be excluded from that definition 

on a case-by-case basis if they meet criteria designed to ensure that they are 

not and cannot reasonably be expected to serve as drinking water sources. 40 

C.F.R. §§144.7, 146.4. The aquifer exemption mechanism thus provides the means 

by which aquifers that will not really be drinking water sources - and thus do 

not warrant protection from "endangerment" under the Safe Drinking Water Act - 

can be excluded from EPA’s otherwise overbroad "USDW" definition. 

Unfortunately - as the preamble to the proposed rule notes - the aquifer 

exemption process has effectively been disabled in certain contexts. In 

particular, EPA - relying on "policies" that lack any basis in law or regulation 

- has generally refused to consider aquifer exemption requests for non-injection 

formations or for hazardous waste injection. 73 Fed. Reg. at 43512. Rather 

than preventing underground injection that "endangers drinking water sources" as 

the statute requires, this approach arbitrarily prevents injection that does not 

endanger any drinking water sources; in effect, it requires the protection of 

aquifers that are not worthy of protection - and that EPA may not even be 

authorized to protect - under the Safe Drinking Water Act. 

The "policy" banning aquifer exemptions for hazardous waste injection is 

inappropriate and lacks any reasonable basis. If a formation is not a drinking 

water source, it does not warrant protection under the Safe Drinking Water Act 

and should not be considered a "USDW." The fact that hazardous waste injection 

is involved has nothing to do with whether the aquifer is legitimately a 

drinking water source, and - far from being considered a determinative factor - 

it should not be considered in the aquifer exemption context at all. The fact 

that hazardous waste injection is involved certainly should not preclude any 

consideration of the technical merits of an aquifer exemption request, yet that 

is precisely the effect of EPA’s existing "policy" (which really amounts to an 

uncodified rule). 

The situation is no different with respect to the "policy" against aquifer 

exemptions for non-injection formations. Because several categories of 

injection (hazardous waste injection being but one) must occur below the 

lowermost USDW, aquifer exemptions for non-injection formations can be necessary 

in order for injection into overlying injection zones to occur. In this 

situation, there is no reason to foreclose any merits-based consideration of 

whether the non-injection formation is legitimately a source of drinking water. 

Either the formation is legitimately a source of drinking water or it is not; 
the fact that the formation is or is not intended for use as an injection zone - 

far from being the determinative factor EPA’s "policy" makes it - has no proper 

relevance at all. 

The existing regulations for aquifer exemptions are specific and detailed. See 

40 C.F.R. §§144.7 and 146.4. These regulations do not include any rules 

precluding aquifer exemptions for non-injection formations or for hazardous 

waste injection, nor do they provide any basis for EPA to impose such rules in 

the guise of "policy." In the proposed rule, EPA has requested comment on 

whether and how it should apply its aquifer exemption rules in the context of 

geologic sequestration, asking in particular whether it should effectively 

overturn its policy against aquifer exemptions for non-injection formations. 73 

Fed. Reg. at 43512. The UIT Group urges EPA to recognize the critical role 

aquifer exemptions should play in harmonizing the regulatory definition of 

"USDW" with the Safe Drinking Water Act’s directive that EPA develop regulations 

preventing injection that endangers drinking water sources. EPA’s policies 

disabling the aquifer exemption process for hazardous waste injection and noninjection formations are arbitrary, and by definition they are unnecessary for 

the protection of drinking water sources. Accordingly, they should be abandoned 

so that the aquifer exemption rules can be applied as written. This approach 

would be appropriate for all classes of injection wells, including wells used 

for geologic sequestration of carbon dioxide. Without this change, it is 

entirely illusory to suggest that the aquifer exemption process could provide 

any means for ameliorating EPA's unnecessary limitation of geological 

sequestration to formations below the lowermost USDW. 

Response: EPA disagrees that the Agency’s policy regarding aquifer exemptions is either arbitrary

or lacking any basis in law or regulation. EPA acknowledges that there are limited circumstances

where aquifer exemptions for GS may be warranted. The final rule allows for the expansion of the

areal extent of existing aquifer exemptions for Class II EOR/EGR wells transitioning to Class VI

injection for GS pursuant to requirements at §§146.4 and 144.7(d). Class VI owners or operators

granted expansions of existing Class II EOR/EGR aquifer exemptions for GS projects must meet all

of the tailored requirements for GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 

EPA clarifies that the final GS rule is not changing existing Agency policy. Rather the Agency

developed the waiver process to address comments and concerns about current and future drinking

water resources and the use of climate mitigation technology at appropriate sites. The aquifer

exemption requirements in the final rule provide flexibility and afford owners or operators an

opportunity to assess and select a suitable GS site while also preserving and protecting USDWs (i.e.,

formations/aquifers afforded SDWA protection). Class VI owners or operators granted expansions of

existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored

requirements for GS wells in the final GS rule. EPA adds that comments related to aquifer

exemptions for injection of hazardous waste are outside the scope of the GS rulemaking.

This approach is designed to ensure that the differences between traditional Class II EOR/EGR

operations and Class VI operations are considered during the aquifer exemption application process
and the Class VI permitting process. These differences include the anticipated large CO2 injection

volumes associated with GS, the buoyant and mobile nature of the injectate, and its corrosivity in the

presence of water. The Agency believes that this process will encourage owners or operators and

Directors to consider the use of alternative formations for GS, including non-USDW formations

through the waiver process, prior to applying for or approving aquifer exemption expansions for

Class II EOR/EGR wells transitioning to Class VI GS operations. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Commenter Name: Robert F. Voorhees Letter ID: 0243

Commenter Organization: Underground Injection Technology Group (UIT

Group)

Comment ID:

23341

Comment: For the reasons presented herein, the UIT Group urges EPA to revise its 

purported "policies" with respect to aquifer exemptions to eliminate all 

existing restrictions on the availability of aquifer exemptions that the 

regulations themselves do not impose. The UIT Group also urges EPA to: (1) 

Response: As described above, EPA clarifies that the final GS rule is not changing existing Agency

policy. Rather the Agency developed the waiver process to address comments and concerns about

current and future drinking water resources and the use of climate mitigation technology at

appropriate sites. The aquifer exemption requirements in the final rule provide flexibility and afford

owners or operators an opportunity to assess and select a suitable GS site while also preserving

USDWs (i.e., formations/aquifers afforded SDWA protection). Class VI owners or operators granted

expansions of existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the

tailored requirements for GS wells in the final GS rule.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24815

Comment: EPA Notice Questions: 73 FR 43512 

EPA Rule Issue: 25. EPA is also requesting comments on whether aquifer 

exemptions should be allowed for the purpose of Class VI injection, and under 

what conditions should such aquifer exemptions be approved. EPA Notice 43512. 

GWPC CO2 Committee Response: The committee recommends that aquifer exemptions be 

allowed. At this time, the Committee is not recommending any specific need for 

new aquifer exemption criteria created because the existing criteria are 

perceived to be sufficient to allow aquifer exemptions as needed for GS. Even 

without changes, the aquifer exemption requirements in the UIC program would 

allow operators to obtain appropriate exemptions for GS operations. 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for
GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. If an owner or operator applies for a

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above

and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR

operations and Class VI operations are considered during the aquifer exemption application process

and the Class VI permitting process. These differences include the anticipated large CO2 injection

volumes associated with GS, the buoyant and mobile nature of the injectate, and its corrosivity in the

presence of water. The Agency believes that this process will encourage owners or operators and

Directors to consider the use of alternative formations for GS, including non-USDW formations

through the waiver process, prior to applying for or approving aquifer exemption expansions for

Class II EOR/EGR wells transitioning to Class VI GS operations.

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Letter ID: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22811

Comment: III A. 4 Proposed Injection Well Operating Requirements 

Z. EPA is also requesting comments on whether aquifer exemptions should be 

allowed for the purpose of Class VI injection, and under what conditions should 

such aquifer exemptions be approved. 

IOGCC Response: Aquifer exemptions under Class VI should be allowed on the 

same basis as for other classes. Each exemption should be considered on its own 

merits based on local geologic conditions and the likelihood of use of the zone 

for future public water supply. 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 
EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. If an owner or operator applies for a

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above

and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR

operations and Class VI operations are considered during the aquifer exemption application process

and the Class VI permitting process. These differences include the anticipated large CO2 injection

volumes associated with GS, the buoyant and mobile nature of the injectate, and its corrosivity in the

presence of water. The Agency believes that this process will encourage owners or operators and

Directors to consider the use of alternative formations for GS, including non-USDW formations

through the waiver process, prior to applying for or approving aquifer exemption expansions for

Class II EOR/EGR wells transitioning to Class VI GS operations.

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment

Commenter Name: Kevin Frederick Letter ID: 0525

Commenter Organization: Wyoming Department of Environmental Quality Comment ID: 21403

Comment: Furthermore, we support allowing directors to exempt aquifers for the purpose of 

CO2 injection in accordance with the requirements of 40CFR 144.7. This 

essentially allows directors upon accepting primacy to exempt aquifers which he 

specifically identifies. 

We support allowing directors to exempt aquifers for the purpose of CO2 

injection in accordance with the requirements of 40CFR 146.4. This allows 

exemption of aquifers if they contain hydrocarbons, mineable minerals are 

contaminated or are located at a definite location that makes future use 

impractical. 

We support allowing directors to provide for CO2 injection into aquifers 

previously exempted for Class I and Class II injection operations provided that 

the operator obtains a new aquifer exemption for the purpose of geologic 

sequestration. 

Response: EPA acknowledges that there are limited circumstances where aquifer exemptions for GS

may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that

is, aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR

wells to Class VI. 
EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at

the Director's discretion and based on site-specific information. If an owner or operator applies for a

Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above

and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth

requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the

injection zone are protected from endangerment. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR

operations and Class VI operations are considered during the aquifer exemption application process

and the Class VI permitting process. These differences include the anticipated large CO2 injection

volumes associated with GS, the buoyant and mobile nature of the injectate, and its corrosivity in the

presence of water. The Agency believes that this process will encourage owners or operators and

Directors to consider the use of alternative formations for GS, including non-USDW formations

through the waiver process, prior to applying for or approving aquifer exemption expansions for

Class II EOR/EGR wells transitioning to Class VI GS operations.

For additional information on aquifer exemptions for Class VI wells, please see the final rule and

preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request

for Comment.

Comment Code: 4470 2.4.4.4.2 Comments opposing aquifer exemptions in all cases 

Individual Comments

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23681

Comment: EPA Request for Comment: EPA is also requesting comments on whether aquifer 

exemptions should be allowed for the purpose of Class VI injection, and under 

what conditions should such aquifer exemptions be approved. EPA Notice 43512. 

AWWA Response: AWWA does not support aquifer exemptions for the purposes of 

Class VI injection projects. Water resources are becoming extremely limited in 

many parts of the country and many drinking water utilities will be turning to 

alternative supply sources, including brackish and saline groundwater, as well 

as deeper USDWs. 40 CFR 146.4 states that: 

"An aquifer or a portion thereof which meets the criteria for an underground 

source of drinking water...may be determined...to be an exempted aquifer if it 

meets the following criteria: (a) It does not currently serve as a source of 

drinking water; and (b) It cannot now and will not in the future serve as a 

source of drinking water because: (1) It is mineral, hydrocarbon or geothermal 

energy producing, or can be demonstrated by a permit applicant as part of a 

permit application for a Class II or III operation to contain minerals or 

hydrocarbons that considering their quantity and location are expected to be 

commercially producible, (2) It is situated at a depth or location which makes 

recovery of water for drinking water purposes economically or technologically 
impractical; (3) It is so contaminated that it would be economically or 

technologically impractical to render that water fit for human consumption; or 

(4) It is located over a Class III well mining area subject to subsidence or 

catastrophic collapse; or (c) The total dissolved solids content of the ground 

water is more than 3,000 and less than 10,000 mg/l and it is not reasonably 

expected to supply a public water system." 

As previously stated, many drinking water utilities are exploring ground water 

resources that might not have been previously feasible to access or treat. The 

underlined portions of the aquifer exemption regulations are problematic as 

ground water resources that fit these definitions are now being tapped, given 

that much of the easily accessible and/or treatable ground water has already 

been utilized or allocated. By allowing for aquifer exemptions in these cases, 

EPA is precluding their use as a future USDW at a time when the country’s 

remaining ground water resources should be aggressively protected. Therefore, 

AWWA recommends that EPA not allow aquifer exemptions for the purposes of Class 

VI injection. 

Response: EPA believes that there are limited circumstances where aquifer exemptions for GS may

be warranted, and the final GS rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

If an owner or operator applies for a Class VI permit to inject CO2 into a previously exempted

aquifer (non-USDW) that is located above and/or between USDWs, the permit applicant must also

apply for a waiver of the injection depth requirements pursuant to §146.95 to ensure that if a waiver

is granted, USDWs above and below the injection zone are protected from endangerment. 

The Agency developed the waiver process to address comments and concerns about current and

future drinking water resources and the use of climate mitigation technology at appropriate sites. The

aquifer exemption requirements in the final rule provide flexibility and afford owners or operators an

opportunity to assess and select a suitable GS site while also preserving USDWs (i.e.,

formations/aquifers afforded SDWA protection). Class VI owners or operators granted expansions of

existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored

requirements for GS wells in the final GS rule. EPA agrees with the commenter's concerns about

USDW preservation and protection and believes that, in most cases, the injection depth waiver is a

more appropriate option than aquifer exemptions for Class VI injection, and that aquifer exemption

expansions for GS should be granted in limited circumstances. 

EPA agrees that future water resources needs are an important consideration, and believes that the

injection depth waiver process at §146.95 responds to concerns about future drinking water resource

availability and the need to ensure high quality water remains available in sufficient quantities to

supply drinking water supply needs. For additional information on the waiver approach and aquifer

exemptions for Class VI wells, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Commenter Name: Wendy Jacobs Letter ID: 0183

Commenter Organization: Harvard Law School Environmental Law and Policy Comment ID:
Center 25168

Comment: B. Exempting USDWs for the Purpose of GS 

Under current UIC Program regulations, the Director has the discretion to exempt 

USDWs pursuant to 40 C.F.R. § 146.4 when the following conditions are met: 

a) [the USDW] does not currently serve as a source of drinking water; and 

b) It cannot now and will not in the future serve as a source of drinking water

because:

(1) It is mineral, hydrocarbon or geothermal energy producing, or can be

demonstrated by a permit applicant as part of a permit application for a Class

II or III operation to contain minerals or hydrocarbons that considering their

quantity and location are expected to be commercially producible.

(2) It is situated at a depth or location which makes recovery of water for

drinking water purposes economically or technologically impractical;

(3) It is so contaminated that it would be economically or technologically

impractical to render that water fit for human consumption; or

(4) It is located over a Class III well mining area subject to subsidence or

catastrophic collapse; or

(c) The total dissolved solids content of the ground water is more than 3,000

and less than 10,000 mg/l and it is not reasonably expected to supply a public

water system.

40 C.F.R. § 146.4. 

Once a USDW is exempted, it is no longer afforded protection as a USDW, now or

in the future. See 73 Fed. Reg. at 43,512; 40 C.F.R. §144.7(b)(1).

Allowing exemptions of USDWs for the purpose of GS is premature. By definition,

a (non-exempted) USDW is a source that has less than 10,000 mg/L total dissolved

solids, the level that EPA already has determined "can reasonably be expected to

supply any public water system." 42 U.S.C. §300 (h)(d)(2). Thus, given the

expected increase in demand for water resources and the available technology, it

does not make sense to allow current or potential USDWs as GS reservoirs until

it is either cost effective to secure water for human consumption from other

sources or lower risk GS sites are no longer available.

Response: EPA believes that there are limited circumstances where aquifer exemptions for GS may

be warranted, and the final GS rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for
GS wells in the final GS rule.

If an owner or operator applies for a Class VI permit to inject CO2 into a previously exempted

aquifer (non-USDW) that is located above and/or between USDWs, the permit applicant must also

apply for a waiver of the injection depth requirements pursuant to §146.95 to ensure that if a waiver

is granted, USDWs above and below the injection zone are protected from endangerment. 

The Agency developed the waiver process to address comments and concerns about current and

future drinking water resources and the use of climate mitigation technology at appropriate sites. The

aquifer exemption requirements in the final rule provide flexibility and afford owners or operators an

opportunity to assess and select a suitable GS site while also preserving USDWs (i.e.,

formations/aquifers afforded SDWA protection). Class VI owners or operators granted expansions of

existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored

requirements for GS wells in the final GS rule. EPA agrees with the commenter's concerns about

USDW preservation and protection and believes that, in most cases, the injection depth waiver is a

more appropriate option than aquifer exemptions for Class VI injection, and that aquifer exemption

expansions for GS should be granted in limited circumstances. 

EPA agrees that future water resources needs are an important consideration, and believes that the

injection depth waiver process at §146.95 responds to concerns about future drinking water resource

availability and the need to ensure high quality water remains available in sufficient quantities to

supply drinking water supply needs. 

For additional information on the waiver approach and aquifer exemptions for Class VI wells, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Diane VanDe Hei Letter ID: 0213

Commenter Organization: Association of Metropolitan Water Agencies

(AMWA)

Comment ID:

22948

Comment: - 73 FR 43512 - EPA is also requesting comment on whether aquifer exemptions 

should be allowed for the purpose of Class VI injection, and under what 

conditions should such aquifer exemptions be approved. 

Response: AMWA does not believe it is prudent to allow for aquifer exemptions 

for the purpose of Class VI injection as saline aquifers not currently used for 

USDWs could be considered viable drinking water supply in a water-stressed 

environment. AMWA strongly believes that the use of an aquifer for drinking 

water supply should take precedence over all other municipal or industrial uses. 

Response: EPA believes that there are limited circumstances where aquifer exemptions for GS may

be warranted, and the final GS rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

If an owner or operator applies for a Class VI permit to inject CO2 into a previously exempted

aquifer (non-USDW) that is located above and/or between USDWs, the permit applicant must also
apply for a waiver of the injection depth requirements pursuant to §146.95 to ensure that if a waiver

is granted, USDWs above and below the injection zone are protected from endangerment. 

The Agency developed the waiver process to address comments and concerns about current and

future drinking water resources and the use of climate mitigation technology at appropriate sites. The

aquifer exemption requirements in the final rule provide flexibility and afford owners or operators an

opportunity to assess and select a suitable GS site while also preserving USDWs (i.e.,

formations/aquifers afforded SDWA protection). Class VI owners or operators granted expansions of

existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored

requirements for GS wells in the final GS rule. EPA agrees with the commenter's concerns about

USDW preservation and protection and believes that, in most cases, the injection depth waiver is a

more appropriate option than aquifer exemptions for Class VI injection, and that aquifer exemption

expansions for GS should be granted in limited circumstances. 

EPA agrees that future water resources needs are an important consideration, and believes that the

injection depth waiver process at §146.95 responds to concerns about future drinking water resource

availability and the need to ensure high quality water remains available in sufficient quantities to

supply drinking water supply needs. 

For additional information on the waiver approach and aquifer exemptions for Class VI wells, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Commenter Name: Saba Tahmassebi Letter ID: 0218

Commenter Organization: Oklahoma Department of Environmental Quality

(DEQ)

Comment ID:

21564

Comment: 3. Preclude aquifer exemptions. It appears that EPA has struggled with balancing 

the perceived benefits of geologic sequestration with the need to protect USDWs. 

In much of the proposed rule, EPA sets a foundation for protecting the USDWs by 

including specific requirements. EPA then diverges from this foundation by 

suggesting that if it is not feasible to protect the USDWs, one may still 

proceed with sequestration activities by exempting the aquifers. In this 

instance, it appears that EPA considers the benefits of geologic sequestration 

to overweigh the need to protect USDWs. Oklahoma DEQ recommends that EPA not 

consider aquifer exemptions for geologic sequestration. 

Response: EPA believes that there are limited circumstances where aquifer exemptions for GS may

be warranted, and the final GS rule allows for the expansion of the areal extent of existing aquifer

exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to

requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing

Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for

GS wells in the final GS rule.

If an owner or operator applies for a Class VI permit to inject CO2 into a previously exempted

aquifer (non-USDW) that is located above and/or between USDWs, the permit applicant must also

apply for a waiver of the injection depth requirements pursuant to §146.95 to ensure that if a waiver

is granted, USDWs above and below the injection zone are protected from endangerment. 

The Agency developed the waiver process to address comments and concerns about current and
future drinking water resources and the use of climate mitigation technology at appropriate sites. The

aquifer exemption requirements in the final rule provide flexibility and afford owners or operators an

opportunity to assess and select a suitable GS site while also preserving USDWs (i.e.,

formations/aquifers afforded SDWA protection). Class VI owners or operators granted expansions of

existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored

requirements for GS wells in the final GS rule. EPA agrees with the commenter's concerns about

USDW preservation and protection and believes that, in most cases, the injection depth waiver is a

more appropriate option than aquifer exemptions for Class VI injection, and that aquifer exemption

expansions for GS should be granted in limited circumstances. 

EPA adds that all decisions regarding aquifer exemptions for Class VI wells are at the Director's

discretion. If a Director believes that injection depth waivers are not appropriate for a specific site or

for a category of formations within their state, the Director has the authority to not permit such

injections.

EPA agrees that future water resources needs are an important consideration, and believes that the

injection depth waiver process at §146.95 responds to concerns about future drinking water resource

availability and the need to ensure high quality water remains available in sufficient quantities to

supply drinking water supply needs. 

For additional information on the waiver approach and aquifer exemptions for Class VI wells, please

see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data

Availability and Request for Comment.

Comment Code: 4490 2.4.5 Use of tracers and potential impact on human health or ecosystems

(seeking comment) 

Individual Comments

Commenter Name: Karl R. Moor Letter ID: 0109

Commenter Organization: Southern Company, on behalf of Edison Electric

Institute (EEI)

Comment ID:

22000

Other EPA Comment Codes and Descriptions: 4670 2.6.7 Surface air monitoring and/or soil gas

monitoring (seeking comment) 

Comment: Similarly, EPA should not require the use of tracers or soil flux to monitor for 

possible carbon dioxide leaks. Not only are tracers relatively untested when it 

comes to their ability to monitor such leaks - and, in fact, the best tracer for 

monitoring carbon dioxide leaks would be CO2 itself - but they also will not 

transmit information sufficiently early to provide any sort of real protection 

to underground sources of drinking water. Soil flux monitoring is problematic 

because it can result in false positives based on natural variability in the 

earth flux rate. What these requirements would do, however, is signal to the 

public that carbon capture and storage is unsafe because it might be leaking 

CO2, despite the fact that this is very unlikely to happen. The United Nations’ 

Intergovernmental Panel on Climate Change has found that the amount of carbon 

dioxide retained in appropriately sited storage sites is very likely to exceed 

99 percent over 100 years. 
Response: EPA acknowledges that air and soil gas monitoring are subject to variability and may not

be suitable in all settings as a method to ensure USDW protection. However, EPA does not believe

that this should entirely preclude their use. For example, if a leak to the surface is suspected, surface

monitoring could provide vital information on its location and magnitude to assist owners and

operators in identifying what USDWs may have been impacted by a leak. EPA clarifies that the

various air and soil gas monitoring methods (e.g., chambers, eddy covariance, hyperspectral

imaging) all have different capabilities that may prove useful in specific GS projects (Miles et al.,

2005; Pickles and Cover, 2005; IPCC, 2005; Menzies et al., 2001). The occurrence of false positives

will be reduced by comparing monitoring data to baseline data collected prior to injection or from a

nearby area away from the GS project.

The final rule at §146.90(h) retains the allowance for surface air and soil gas monitoring at the

discretion of the Director as a means of identifying leaks that may pose a risk to USDWs and

informing emergency notification of a Class VI owner or operator and UIC Director in the event of a

USDW endangerment, pursuant to requirements at §146.91(c). EPA clarifies that the decision to use

surface monitoring and the selection of monitoring methods will be site-specific (e.g., may be

influenced by geology, injection depth, and operational conditions) and must be based on potential

risks to USDWs within the AoR. 

EPA agrees that the use of tracers should not be required at all GS sites, but should be available as

an option. For this reason, EPA does not require the use of tracers at all GS sites; however, the

Director has discretion to require their use if he/she determines that the use of tracers could improve

monitoring of the site and enhance USDW protection from endangerment. The rule will also allow

their use if proposed by the owner or operator and approved by the Director. 

EPA agrees that the CO2 itself may serve as a tracer in the form of stable isotopes of carbon. For

example, anthropogenic CO2 is depleted in 13C compared to naturally occurring CO2. If tracers are

determined to be necessary at a GS site, this may be an appropriate option.

EPA disagrees that the use of tracers, if needed, would signal to the public that GS is unsafe. EPA

believes that tracers can be useful tools for monitoring, plume tracking, and verification at GS sites

and may help improve public confidence in certain projects. EPA believes that providing the public

with important information about the project, including how tracers would be an integral part of the

site monitoring plan, will be a key part of improving public acceptance of specific projects and GS

technology in general.

Commenter Name: Doug Louis Letter ID: 0121

Commenter Organization: Kansas Corporation Commission Comment ID: 22082

Comment: Proposed Injection Well Operating Requirements 

In the proposed rule, EPA is seeking comment on the use of tracer material for 

detection of fugitive CO2. KCC staff’s opinion is the comparison of baseline CO2 

levels to monitored levels would provide the same information, as would costly 

and potentially harmful tracer material. 

Response: In the final rule, EPA does not require the use of tracers at all GS sites; however, the

Director has discretion to require their use if he/she determines that the use of tracers could improve

monitoring of the site and enhance USDW protection from endangerment. 
If an owner or operator proposes the use of tracers at a GS site, EPA anticipates that the specific

tracers to be used would be described in the testing and monitoring plan, which the Director would

evaluate in the context of other information about the GS site. The Director would assess the use of

tracers in the context of site-specific information, including risks to USDWs.

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24753

Comment: d. delete references to tracers, because of the numerous problems discussed in 

the preamble. 

Response: EPA agrees that tracer use is not appropriate in all situations, and recognizes that some

factors (e.g., the potential to contribute GHGs to the atmosphere, cost, and difficulties associated

with monitoring for tracers) may make other methods of tracking CO2 movement more practical.

For this reason, EPA does not require the use of tracers at all GS sites. Rather, the Director has

discretion to require their use if he/she determines that the use of tracers could improve monitoring

of the site and enhance USDW protection from endangerment. 

EPA clarifies that there are many different types of tracers and not all are problematic; research is

being done to overcome problems with existing tracers. EPA believes that tracers have been used

safely and successfully in other applications. EPA has been following new and ongoing research on

the safety and efficacy of tracers, and believes that, in some circumstances, tracers can be an

effective part of monitoring GS projects. EPA will continue to track research related to tracer use

and plans to, every six years, collect and review data on GS projects to determine whether the

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

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

Commenter Name: Carl Carlsson Letter ID: 0131

Commenter Organization: SUEZ Energy Generation NA, LLC Comment ID: 21534

Comment: below the lowermost non-exempted USDW. SEGNA also supports the 

development of guidelines for cost-effective use of tracers, but the decision to 

require their use should be made by the permitting authority. Of the technical 

options suggested in the proposed rule, unique suites of perfluorocarbons (PFCs) 

appeared to be the best option. 

Response: EPA agrees that tracers can be useful tools for monitoring GS projects. However, EPA

agrees that tracer use is not appropriate in all situations. For this reason, EPA does not require the

use of tracers at all GS sites; however, the Director has discretion to require their use if he/she

determines that the use of tracers could improve monitoring of the site and enhance USDW

protection from endangerment. The rule will also allow their use if proposed by the owner or

operator and approved by the Director.

EPA will continue to track research related to tracer use, and plans to, every six years, collect and

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

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

requirements are appropriate or necessary.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22569
Other EPA Comment Codes and Descriptions: 4670 2.6.7 Surface air monitoring and/or soil gas

monitoring (seeking comment) 

Comment: Although surface monitoring may be needed from a community outreach and 

environmental safety point of view, it is important to note that by the time any 

leakage is detected at the surface it will have already passed by and possibly 

impacted underground drinking waters. Projects like the Frio brine project 

[McCallum et al, 2005] have incorporated tracers as a way to identify CO2 

leakage. The use of non-isotopic tracers, tracers other than C13, C14, and O18 

that occur naturally in CO2, should be studied very carefully for unintended 

environmental effects prior to implementation. 

McCallum, S.D., Riestenberg, D.E., Cole, D.R., Freifeld, B.M., Trautz, R.C., 

Havorka, S.D., and Phelps, T.J., 2005, "Monitoring geologically sequestered CO2 

during the Frio brine pilot test using perfluorocarbon tracers," Proceedings of 

the 4th Annual Conference on Carbon Capture and Sequestration, May 2-5, 2005, 

Monitor and Exchange Publications and Forum, Washington, D.C. 

Response: EPA clarifies that subsurface geochemical and pressure monitoring in the subsurface

formations are the first line of monitoring that would allow detection of potential endangerment to

USDWs from GS activities (this is required at all GS sites, as described at §146.90(d)). The Agency

also believes that surface air and soil gas monitoring, when coupled with subsurface monitoring,

may be appropriate at some GS projects to ensure USDW protection. EPA acknowledges that surface

air and soil gas monitoring may not be suitable in all settings as a method to ensure USDW

protection. However, EPA does not believe that this should entirely preclude their use. The decision

to use surface monitoring and the selection of monitoring methods will be site-specific (e.g., may be

influenced by geology, injection depth, and operational conditions) and must be based on potential

risks to USDWs within the AoR.

If surface monitoring were the only monitoring method employed to ensure USDW protection, direct

correlation of CO2 at the surface with CO2 in the subsurface might be difficult; however, when

combined with information gathered through other monitoring techniques required of GS well

owners and operators (e.g., monitoring wells, geophysical techniques), air and soil gas monitoring

may provide valuable data on the magnitude and location of a leak. The CO2 itself may serve as a

tracer in the form of stable isotopes of carbon. For example, anthropogenic CO2 is depleted in 13C

compared to naturally occurring CO2.

The final rule at §146.90(h) retains the allowance for surface air and soil gas monitoring at the

discretion of the Director as a means of identifying leaks that may pose a risk to USDWs and

informing emergency notification of a Class VI owner or operator and UIC Director in the event of a

USDW endangerment, pursuant to requirements at §146.91(c).

EPA believes that, in some circumstances, tracers can be an important component of a multifaceted

approach to monitoring GS projects. However, the Agency recognizes that tracers may not be

appropriate in all GS projects. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment.

Commenter Name: Patrick Nugent Letter ID: 0143

Commenter Organization: Texas Pipeline Association (TPA) Comment ID: 23136
Comment: techniques would produce reliable data. In addition. there should be no blanket 

requirement for the use of tracers to detect leaks. Such a requirement would 

send an erroneous signal to the public concerning the risks involved in geologic 

sequestration. Geologic sequestration will not develop as a helpful tool in 

reducing greenhouse gas emissions if the wrong signals are sent to the public. 

The utility of tracers for monitoring carbon dioxide leaks is uncertain in any 

event, and the use of tracers may create health or safety issues for workers and 

for the public. 

Response: EPA agrees that the use of tracers should not be required at all GS sites, but should be

available as an option. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment. The rule

will also allow their use if proposed by the owner or operator and approved by the Director.

Comments related to whether the use of tracers will signal to the public that GS is unsafe are outside

the scope of this rulemaking. However, EPA disagrees that the use of tracers, if needed, would signal

to the public that GS is unsafe. EPA believes that tracers can be useful tools for monitoring, plume

tracking, and verification at GS sites and may help improve public confidence in certain projects.

EPA believes that providing the public with important information about the project, including how

tracers would be an integral part of the site monitoring plan, will be a key part of improving public

acceptance of specific projects and GS technology in general.

Commenter Name: Dan Evans Letter ID: 0144

Commenter Organization: Praxair Services, Inc. Comment ID: 23146

Comment: In its draft UIC rule for CO2 GS wells, EPA requests specific comments regarding 

the applicability, costs, and potential impacts on human health and ecosystems 

(including the potential impact on global warming) of PFCs as tracers. As an 

entity with considerable experience in this area, Praxair Services is submitting 

comments on this proposed rule for the purpose of providing data that indicates 

that such risks are minimal in the context of PFC tracer use in this 

application. 

Background: Praxair Services Use of PFC Tracers in GS Well Operation and 

Monitoring 

The general use of PFCs as tracers dates back to the 1980s and is a wellestablished practice that experts view as an environmentally safe, reliable and 

effective method for monitoring the movement of fluids both below and above 

ground. Praxair Services has been conducting tracer tests since the mid-1980s. 

In that time, Praxair Services has conducted thousands of successful tests in 

the U.S. and Canada. In its experience with tracers for a variety of 

applications, including GS well monitoring, Praxair Services believes this 

application of tracers can be an effective tool in accomplishing the goals of 

the UIC program. 

Specific to the UIC program, Praxair Services has participated in PFC studies of 

fluid movement in a number of areas. These include various CO2 injection 

projects, a mixing study in a salt cavern and several surface monitoring tests 
to detect gas releases from a natural gas storage field. These tests, as well 

as those conducted by others, have demonstrated the value of using tracers, 

including PFCs, for monitoring fluid movement in conjunction with CO2 

sequestration projects. 

Praxair Services has and is currently participating in tests with the U.S. 

Department of Energy (DOE), including the on-going pilot study at Plant Daniel 

in Mississippi and the completed Frio sequestration project in Texas. In the 

Frio test, PFC tracers were utilized to monitor surface releases of the CO2 

injected into a geologic storage formation over the course of several months. 

We discuss results from the tests and specific recommendations regarding proper 

and careful application of tracers in subsequent sections of these comments. 

Benefits: Use of PFC Tracers in GS Well Monitoring and Operation 

The benefits of using tracers in the UIC program can generally be divided into 

two categories: "Operation and Injection" and "Monitoring" of GS wells under the 

UIC program. In terms of value provided by such use during the operation and 

injection phases of a sequestration project, PFCs as tracers offer several 

unique advantages over other detection devices or methods. 

First, by injecting CO2 with tracers, the injecting entity can tag injections by 

time, producer and location. Among other benefits, this would allow assignment 

of leaking CO2 from a shared GS well to the appropriate party during such an 

occurrence. The additional data would also allow for better information 

regarding potentially contaminated CO2 and its source and better estimation 

regarding the test interval and timing of a CO2 leak. Such information would 

likely allow entities to determine more quickly where CO2 is leaking and to stop 

the leak. 

Second, the use of tracers allows for the monitoring of the movement of the CO2 

through the formations in the subsurface. This provides additional value as one 

can track migration of CO2 in the subsurface in conjunction with surface leaks, 

and to the extent action is needed to stop or alter migration, entities would be 

able to react more quickly and more precisely when such events occur. 

In terms of monitoring CO2 after injection, PFCs as tracers also allow for 

better accuracy at a relatively low cost when determining if and where a CO2 

leak is occurring. 

Because tracers can be detected at low concentrations when tests are conducted 

appropriately, even small leaks can be detected accurately in a reasonable 

period of time. Further, the specialized field equipment used by experienced 

tracer test teams is extremely reliable, and due to the benefits associated with 

the ability to tag different CO2 streams, the location of a leak can be 

determined quickly before large releases of CO2 can occur. 

Moreover, PFCs as tracers are critical to, and effective in, a successful ongoing monitoring program. Once the tracer is injected into a well with a set 

amount of CO2 there are no on-going tracer injection requirements for that given 
quantity of CO2. The only on-going cost and operational task is the periodic 

re-testing of the above ground or subsurface environments to determine if any 

leaks or migrations of CO2 are occurring. When combined with other testing 

methods and devices, such a monitoring program can detect CO2 releases quickly 

with near certain accuracy. 

For these reasons and others, Praxair Services believes tracers are well suited 

to meet the goals of the UIC program for GS wells. 

Section III-A-4: Proposed Injection Well Operating Requirements: Tracers 

* Cost effectiveness of tracer monitoring programs 

In response to the EPA concern about the cost of PFC tracers discussed in the 

proposed rule, Praxair Services offers the following comments. 

Praxair Services believes the cost associated with the use of PFCs as tracers is 

manageable for the majority of applications for which tracers are suitable in 

the UIC program, but recognizes that their effectiveness depends on the 

application and concentration within the GS well. 

Praxair Services calculates that the PFC tracers can be used effectively at part 

per billion (ppb) levels in the geologically stored CO2 to obtain the desired 

result. Estimated costs for the tracers themselves range from $80 to $400 per 

pound. This would equate to the addition of 1 ppb of tracer adding $2 to $10 to 

the cost of injecting 1,000 tons of CO2. Such a cost distribution would 

represent less than 0.04% of average estimates for the total injection and 

storage costs for a typical GS project. 

* Elimination of "False positives" 

In response to the EPA request for comments in the proposed rule regarding a 

concern about the risk of "false positives" for tracers used in this 

application, Praxair Services offers the following comments. 

During its 24-year history, Praxair Services has come to realize that so called 

"false positives" in tracer tests are in reality only unidentified sources of a 

leak of the tracer. Identification of the source is the most critical piece of 

a successful tracer test as it simplifies and confirms the interpretation of the 

test results. 

In order to accurately identify a source, any tracer test relies on the design 

of the plan for collecting samples. For release detection applications, an 

elevated concentration of tracer in a surface sample is an indication of a 

release. There are many sources from which such a surface leak could be 

detected including: 

o From the CO2 container or apparatus used to inject it; 

o From piping used to convey the CO2 to the injection well; 

o From the injection well or other wells in the vicinity of the test; or 
o From the formation itself. 

Each of these releases has a specified test method that is employed in order to 

ensure there are no "false positives". For example, releases from the tracer 

container and injection apparatus can be controlled by careful handling. 

Releases from surface piping and wells are readily identifiable using strategic 

samples and testing protocol. Tracer emanating from the subsurface is also 

straight forward to identify with the proper methodology. For these reasons, 

Praxair Services believes the technical challenge of avoiding false positives 

can be successfully resolved through careful use with test methodology 

specifically developed for the UIC program applications. 

Texas Tracer Demonstration: Need for Accurate Source Identification 

As highlighted above, PFC tracers were added to the Gulf Coast Carbon Center’s 

CO2 injection at Frio, TX. In this test, passive samples were collected to be 

analyzed for the presence of tracer after injection. Samples were collected by 

opening an absorbent tube and leaving it on the site for days or weeks. The 

tubes were then collected and analyzed. 

The results from the samples collected at Frio showed elevated concentrations of 

tracers at several locations around the injection site. There was no other 

indication of CO2 leakage. Because of the limited number of samples, 

interpretation of the source of tracer was difficult to determine. The data led 

many to assume that the detections were a "false positive". 

Several months later Praxair Services conducted an additional survey. Several 

samples were again collected. Analysis indicated that the highest 

concentrations of tracer were near the observation well. A probe was then 

inserted into the ground to collect a sample of soil gas at selected depths. 

The depth profile sample showed a very rapid decrease in the concentration of 

tracer indicating an above ground source. Additional samples collected around 

the well head led the team to discover a faulty fitting as the source of the 

leak. 

The above example highlights a significant benefit of bringing tracer analytical 

equipment to the injection site which is the ability to quickly identify the 

source of any release of the tracer. This benefit includes the ability to: 

o Locate a leaking well or well head; 

o Distinguish surface releases between the tracer container and the well head 

from subsurface releases from the well boring to the surface; and 

o Identify and locate releases of tracer to the surface from the formation. 

f properly conducted, a tracer test will not yield a false positive. However, 

if not conducted properly, the results can be difficult to interpret and can 

leave a tracer source unidentified and improperly referred to as a false 

positive. Therefore, to the extent the rule should recognize concerns about 

"false positives", we recommend that such concerns be represented in the context 

of proper injection of the tracer on a project-by-project basis. For this 
reason, organizations that participate in such tests should be well-established 

and have a demonstrated track record in successfully using tracer technology. 

* Global Warming Potential ("GWP") of PFC Tracers 

It the proposed rule, EPA suggests concern for the GWP of PFC tracers in this 

application. Praxair Services offers the following comments. 

In considering the impact of the PFC tracers on global warming, EPA should 

consider the significantly lower relative contribution of injected PFC tracers 

to the total CO2 that could be released from GS locations if not detected. In 

addition, at the ppb level, the absolute amount of tracers injected is limited. 

Generally, there should be a balance between potential reductions in releases of 

CO2 by utilizing tracer technology and the contribution of any small amount of 

PFC to the atmosphere. 

After careful evaluation of published materials, Praxair Services believes that 

a reasonable upper limit for the global warming potentials of PFC tracers 

relative to CO2 is in the range of 10,000 [1,2]. Again, even though the 

contribution per molecule is high, the greenhouse gas contribution added by ppb 

levels of PFC tracers in the CO2 is negligible. For example, in the event of a 

release of the tracer-labeled CO2, a 1 ppb concentration of PFC tracer with a 

GWP of 10,000 would increase the greenhouse contribution of the release by 10 

parts per million. The presence of the tracer would be equivalent to adding 1 

additional ton of CO2 to a release of 100,000 tons of CO2. On balance, we 

respectfully suggest that this is an acceptable risk given the rewards gained in 

leak detection from the use of tracers. 

* PFC Tracer effects on water quality, human health and ecosystems 

In the proposed rule, EPA also requests comments regarding the effects of PFC 

tracer on water quality, human health and ecosystems in this application. 

Praxair Services offers the following comments. 

The wording of the rule should reflect the demonstrated environmental safety of 

certain classes of tracers, such as PFC tracers and noble gases, as documented 

by experts in the scientific community. 

PFCs are chemically and biologically inert and, to the best of our knowledge and 

belief, present little direct threat to human health or ecosystems. This 

limited risk has been recognized in approvals by the U.S. EPA and the California 

Air Resources Board (CARB) regarding the release of PFCs into the atmosphere and 

occupied buildings during tracer studies conducted by Brookhaven National 

Laboratory. The absence of known hazards is also referenced in a research paper 

prepared for the Texas Commission on Environmental Quality with respect to an 

injection well permit. The paper notes that PFC compounds have "no known human 

or eco-toxicity"[3]. 

In addition, given the application type, the levels of PFC tracers used (parts 

per billion) are likely to be negligible. If tracers do enter the environment, 
they are detectable at extremely low levels in water samples or in samples 

collected above an aquifer. Praxair Services encourages the EPA to review data 

from available sources that support the absence of known hazards from the use of 

very low levels of PFC tracers. 

Section III-A-6: Proposed Plume and Pressure Front Monitoring Requirements 

* Effectiveness of Tracers for CO2 detection 

In the proposed rule EPA expresses concern regarding the ability to detect 

releases of CO2 by monitoring increases in the background level of CO2. The 

rule further indicates that detection of an increase in the level of CO2 in the 

atmosphere may only be effective for large releases due to high and potentially 

variable background concentrations at or below the ground surface. In response, 

Praxair Services offers the following comments: 

The concerns expressed by EPA in the proposed rule highlight the usefulness of 

PFCs as tracers in this application. Generally, PFC concentrations in the 

atmosphere are very low (less than 1 part in 1014) and PFC background 

concentrations are relatively constant. In addition, while there are no 

subsurface sources of PFCs, soils typically emit CO2 because the concentration 

in soil gas is higher than in the atmosphere, sometimes many times higher. 

Vegetation is also a local source of CO2 in both the subsurface and surface 

environments. Such circumstances cause variability in the CO2 background 

concentration and that variability makes small changes in CO2, and their source, 

difficult to detect, whereas increases in PFCs are much simpler to identify and 

measure due to the low and consistent nature of background PFC. 

For example, a surface release from a GS well with PFC tracers (at a 

concentration of 1 ppb) that caused a 10% increase in background CO2 would cause 

the PFC background to increase more than 400%, a relative increase that is at 

least 40 times greater and much easier to detect and identify the source of 

emission. Praxair Services believes the use of a PFC as a tracer, when used 

properly and in the correct application, makes the determination of such a 

release less ambiguous and reduces the size of a detectable release both at the 

surface and subsurface levels due to such properties. 

In summary, Praxair Services believes the effectiveness of a release monitoring 

program can be significantly improved by the use of PFC tracer technology due to 

the ability of these types of tracers to more accurately track releases at a 

relatively low cost level. We hope that the EPA will encourage the use of PFCs 

as tracers in its final rule for UIC for GS wells. 

1 IPCC/TEAP Special Report: Safeguarding the Ozone Layer and the Global Climate 

System, 2003. 

2 Keith P. Shine, et al, "Perfluorodecalin: global warming 

potential and first detection in the atmosphere,"Atmospheric Environment, 

Volume 39, Issue 9, pages 1759-1763, 1/11/05. 
3 Susan D. Hovorka and Mark H. Holtz and Shinichi Sakurai and Paul R. Knox, 

Bureau of Economic Geology and John A. and Katherine G. Jackson, School of 

Geosciences, The University of Texas at Austin and Dan Collins and Phil Papadeas 

and Donald Stehli, Sandia Technologies, LLC, Report to the Texas Commission on 

Environmental Quality to Accompany a Class V Application for an "Experimental 

Technology Pilot Injection Well Frio Pilot in CO2 Sequestration in Brine-Bearing 

Sandstones", page 157, December 2003. 

Response: EPA agrees that tracers can be useful tools for monitoring GS projects. However, EPA

believes—as some commenters note—that tracer use is not appropriate in all situations. For this

reason, EPA does not require the use of tracers at all GS sites; however, the Director has discretion

to require their use if he/she determines that the use of tracers could improve monitoring of the site

and enhance USDW protection from endangerment. The rule will also allow their use if proposed by

the owner or operator and approved by the Director.

If an owner or operator proposes the use of tracers at a GS site, EPA anticipates that the specific

tracers to be used will be described in the testing and monitoring plan, which the Director will

evaluate in the context of other information about the GS site. The Director would assess the use of

tracers in the context of site-specific information, including risks to USDWs. 

EPA continues to follow new and ongoing research on the safety and efficacy of tracers, including

the Frio study mentioned by the commenter. For example, studies at the Frio Brine Pilot Experiment

site (Dayton, TX) used various types of tracers, including PFTs, sulfur hexafluoride, and the noble

gases krypton, neon, and xenon. These studies (e.g., Phelps and Cole, 2008; Hovorka et al. 2005)

found that tracers can provide useful CO2 monitoring information at injection wells as well as nearsurface locations. At Frio, tracers enabled quantification of CO2 plume behavior and provided a

technique for model validity testing (McCallum et al., 2005). EPA will continue to track research

related to tracer use. 

EPA agrees that tracers can support a multifaceted approach to monitoring GS projects, and that

false positive detections can be managed (i.e., by the use of available test methods for detecting the

sources of the false positives, as the commenter notes).

Commenter Name: Brianne Metzger Letter ID: 0151

Commenter Organization: Spectra Energy Corp Comment ID: 21838

Comment: EPA has specifically requested comment on the use of tracers. Based on our 

experience, tracers are not typically used for monitoring the movement of the 

CO2 plume, unless it is suspected that leakage is occurring, and then they are 

only used to trace the leakage. The use of tracers can be very expensive and 

the results can take considerable time to develop, analyze, and understand. 

Radioactive tracers typically have long shelf lives (e.g., 50 or 100 years) 

and, if used too frequently by neighboring operators, could produce conflicting 

and indeterminate results. Due to the potential for groundwater contamination, 

the use of radioactive materials should be used only sparingly and for targeted 

purposes. 

Response: EPA believes that, in some circumstances, tracers can be an important component of a

multifaceted approach to monitoring GS projects. However, the Agency recognizes that tracers may

not be appropriate in all GS projects. For this reason, EPA does not require the use of tracers at all
GS sites; however, the Director has discretion to require their use if he/she determines that the use of

tracers could improve monitoring of the site and enhance USDW protection from endangerment. 

While the intent of the GS regulations is to prevent leaks of CO2 to USDWs, EPA clarifies that all

of the protective components of the regulation, including a comprehensive monitoring program per

§146.90 (which includes testing of the well, ground water quality monitoring, and tracking of the

CO2 plume and pressure front) support a multi-barrier approach to protecting USDWs. Additionally,

some studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005) found that

tracers can provide useful CO2 monitoring information at injection wells both at depth and at nearsurface locations. At Frio, tracers enabled quantification of CO2 plume behavior and provided a

technique for model validity testing (McCallum et al., 2005). EPA will continue to track research

related to tracer use. The Agency plans to, every six years, collect and review data on GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

Commenter Name: James Dooley Letter ID: 0156

Commenter Organization: Joint Global Change Research Institute, Pacific

Northwest National Laboratory

Comment ID:

22662

Comment: - Page 43513. EPA should not require that tracers be used in all GS 

applications across the very heterogeneous set of deep geologic formations that 

could be used to store CO2 in the USA. The USEPA (and in particular the Office 

of Air and Radiation) might want to consider doing full life-cycle analyses of 

the manufacture, storage, use and potential leakage of tracers to help better 

inform the technical community about the cost / benefits of using this one class 

of MMV technologies. 

Response: EPA agrees that tracer use is not appropriate in all situations. For this reason, EPA does

not require the use of tracers at all GS sites; however, the Director has discretion to require their use

if he/she determines that the use of tracers could improve monitoring of the site and enhance USDW

protection from endangerment. The rule will also allow their use if proposed by the owner or

operator and approved by the Director.

Commenter Name: James Childress Letter ID: 0158

Commenter Organization: Gasification Technologies Council (GTC) Comment ID: 23785

Comment: EPA's proposal allows Directors' discretion on whether to require the use of 

tracers, and if so, what types of tracers. EPA seeks comment on the use of 

tracers in CO2 GS operations, and any potential impact of tracers on human 

health or ecosystems as they relate to USDWs. EPA Notice 95. 

Tracers should be permitted, but not required. They are commonly and safely used 

in the oil and gas industry. 

Response: EPA agrees that tracer use is not appropriate in all situations. For this reason, EPA does

not require the use of tracers at all GS sites; however, the Director has discretion to require their use

if he/she determines that the use of tracers could improve monitoring of the site and enhance USDW

protection from endangerment. The rule will also allow their use if proposed by the owner or

operator and approved by the Director.
Commenter Name: Michael J. Miller Letter ID: 0168

Commenter Organization: Electric Power Research Institute (EPRI) Comment ID: 22506

Comment: Preamble, page 43513: "EPA seeks comment on the use of tracers in CO2 GS 

operations, and any potential impact of tracers on human health or ecosystems as 

they relate to USDWs." 

EPRI COMMENT #12: Too little is known about how tracers (especially PFT's) 

partition between the CO2, water and oil phase and how they adsorb onto organic 

or mineral surfaces at reservoir conditions (high temperatures and pressure) to 

conclude that they act as conservative tracers. Any tracer added to the CO2 that 

is soluble in water will lose mass to the water phase and will not act as a 

conservative tracer for the CO2 phase. EPA should not require the use of tracers 

unless and until more is known about their fate and transport. 

Response: EPA agrees that the use of tracers should not be required at all GS sites, but should be

available as an option. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment. The rule

will also allow their use if proposed by the owner or operator and approved by the Director.

EPA continues to follow new and ongoing research on the safety and efficacy of tracers. For

example, studies at the Frio Brine Pilot Experiment site (Dayton, TX) used various types of tracers,

including perfluorocarbon tracers (PFTs), sulfur hexafluoride, and the noble gases krypton, neon,

and xenon. These studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005)

found that tracers can provide useful CO2 monitoring information at injection wells at depth and at

near-surface locations. At Frio, tracers enabled quantification of CO2 plume behavior and provided a

technique for model validity testing (McCallum et al., 2005). EPA will continue to track research

related to tracer use. The Agency plans to, every six years, collect and review data on GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

Commenter Name: Theresa Pugh Letter ID: 0169

Commenter Organization: American Public Power Association Comment ID: 23422

Comment: Tracers - If the state Director believes that tracers are needed, we encourage 

the least cost tracer be selected from the most effective options. EPA correctly 

notes that some drawbacks can accompany the use of tracers, including the 

possibility of false positives. Id. at 43512-13. 

Response: EPA agrees that the use of tracers should not be required at all GS sites, but should be

available as an option. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment. The rule

will also allow their use if proposed by the owner or operator and approved by the Director. 

EPA adds that, if tracers are warranted at a site, the specific tracers to be used would be described in

the testing and monitoring plan, which the Director would evaluate in the context of other

information about the GS site. The Director would assess the use of tracers in the context of site-
specific information, including risks to USDWs.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24242

Comment: Rule Provisions: 73 FR 43513-15 

EPA Preamble Question: 27. EPA’s proposal allows Directors’ discretion on 

whether to require the use of tracers, and if so, what types of tracers. EPA 

seeks comment on the use of tracers in CO2 GS operations, and any potential 

impact of tracers on human health or ecosystems as they relate to USDWs. EPA 

Notice 43513. 

API Response: EPA should not mandate the use of tracers. The value of tracers 

has been questioned by many. Further research of their use needs to be conducted 

before any final language is approved. Modeling and monitoring are much more 

reliable techniques for tracking the plume of injected CO2. 

Response: EPA agrees that the use of tracers may not be appropriate at all GS sites, but should be

available as an option. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment. The rule

will also allow their use if proposed by the owner or operator and approved by the Director.

EPA continues to follow new and ongoing research on the safety and efficacy of tracers. For

example, studies at the Frio Brine Pilot Experiment site (Dayton, TX) used various types of tracers,

including perfluorocarbon tracers (PFTs), sulfur hexafluoride, and the noble gases krypton, neon,

and xenon. These studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005)

found that tracers can provide useful CO2 monitoring information at injection wells at depth and at

near-surface locations. At Frio, tracers enabled quantification of CO2 plume behavior and provided a

technique for model validity testing (McCallum et al., 2005). EPA will continue to track research

related to tracer use. 

EPA has been following new and ongoing research on the safety and efficacy of tracers, including

their efficiency and cost-effectiveness. The Agency plans to, every six years, collect and review data

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

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

are appropriate or necessary.

Commenter Name: James Rower Letter ID: 0173

Commenter Organization: Utility Solid Waste Activities Group (USWAG) Comment ID: 23497

Comment: Tracers - The use of tracers should not be required for CO2 GS operations, even 

if only at the discretion of the Director. EPA correctly notes that many 

drawbacks can accompany the use of tracers, including the possibility of false 

positives, the release of PFCs to the atmosphere, and uncertainty regarding 

cost-effectiveness. Id. at 43512-13. These negative aspects argue against 

allowing the Director to exercise discretion to require the use of tracers. If 

anything, the use of tracers should only be an option available at the 

discretion of Owners or Operators, subject to the approval by the Director. 
Response: EPA agrees that the use of tracers may not be appropriate for all GS sites, but should be

available as an option. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment. The rule

will also allow their use if proposed by the owner or operator and approved by the Director.

Commenter Name: Kenneth Nemeth Letter ID: 0176

Commenter Organization: Southern States Energy Board Comment ID: 23543

Other EPA Comment Codes and Descriptions: 4670 2.6.7 Surface air monitoring and/or soil gas

monitoring (seeking comment) 

Comment: pressure front. CO2 monitoring should be fit for purpose. Air and soil gas 

monitoring is unlikely to be beneficial, and the use of tracers should be at the 

discretion of the owner/operator. 

Response: EPA acknowledges that air and soil gas monitoring to ensure USDW protection is not

necessary at all GS sites and agrees that the decision to use surface monitoring and the selection of

monitoring methods for the purpose of USDW protection will be site-specific.

The Agency believes that surface air and soil gas monitoring, when coupled with subsurface

monitoring, may be appropriate at some GS projects to ensure USDW protection. EPA also

acknowledges that surface air and soil gas measurements are subject to variability and may not be

suitable in all settings as a method to ensure USDW protection. However, EPA does not believe that

this should entirely preclude their use. The decision to use surface monitoring and the selection of

monitoring methods will be site-specific (e.g., may be influenced by geology, injection depth, and

operational conditions) and must be based on potential risks to USDWs within the AoR. 

If surface monitoring were the only monitoring method employed to ensure USDW protection, direct

correlation of CO2 at the surface with CO2 in the subsurface might be difficult; however, when

combined with information gathered through other monitoring techniques required of GS well

owners and operators (e.g., monitoring wells, geophysical techniques), air and soil gas monitoring

may provide valuable data on the magnitude and location of a leak. The CO2 itself may serve as a

tracer in the form of stable isotopes of carbon. For example, anthropogenic CO2 is depleted in 13C

compared to naturally occurring CO2.

In the final rule, at §146.90(h), the decision to require such monitoring as an additional measure to

ensure USDW protection rests with the Director as a means of identifying leaks that may pose a risk

to USDWs and informing emergency notification of a Class VI owner or operator and UIC Director

in the event of a USDW endangerment, pursuant to requirements at §146.91(c).

EPA agrees that the use of tracers may not be appropriate for all GS sites, but should be available as

an option. For this reason, EPA does not require the use of tracers at all GS sites; however, the

Director has discretion to require their use if he/she determines that the use of tracers could improve

monitoring of the site and enhance USDW protection from endangerment. The rule will also allow

their use if proposed by the owner or operator and approved by the Director.

Commenter Name: Quinlan J. Shea Letter ID: 0177

Commenter Organization: Edison Electric Institute Comment ID: 23553

Other EPA Comment Codes and Descriptions: 4670 2.6.7 Surface air monitoring and/or soil gas
monitoring (seeking comment) 

Comment: EEI is also concerned about proposed requirements related to monitoring for 

potential CO2 movement and the use of tracers. Under the proposed regulations, 

the UIC program director would have discretion to require the use of tracers or 

surface air/soil gas monitoring "to detect movement of CO2 that could endanger a 

USDW." Tracers and surface air/soil gas monitoring should not be required, and 

may create an overly negative and unwarranted public perception regarding the 

safety of GS projects or tracers. 

Response: EPA believes that monitoring at a GS site is of critical importance to ensuring protection

of USDWs from endangerment. Appropriately selected monitoring technologies, including surface

air and soil-gas monitoring will also serve to increase public confidence in the safety of GS and to

assure the public that GS projects are being appropriately operated and monitored. The information

gained through such monitoring will also enable permitting authorities to take appropriate steps to

address any indication that USDWs may be endangered. 

If surface monitoring were the only monitoring method employed to ensure USDW protection, direct

correlation of CO2 at the surface with CO2 in the subsurface might be difficult; however, when

combined with information gathered through other monitoring techniques required of GS well

owners and operators (e.g., monitoring wells, geophysical techniques), air and soil gas monitoring

may provide valuable data on the magnitude and location of a leak. The CO2 itself may serve as a

tracer in the form of stable isotopes of carbon. For example, anthropogenic CO2 is depleted in 13C

compared to naturally occurring CO2. 

EPA clarifies that surface air and soil gas monitoring are not required at all GS sites. However, the

GS rule at §146.90(h) gives the Director discretion to require surface air and/or soil gas monitoring

as a means of identifying leaks that may pose a risk to USDWs and informing emergency

notification of a Class VI owner or operator and UIC Director in the event of a USDW

endangerment, pursuant to requirements at §146.91(c).

Regarding the use of tracers, EPA agrees that tracers may not be appropriate for all GS sites, but

should be available as an option. For this reason, EPA does not require the use of tracers at all GS

sites; however, the Director has discretion to require their use if he/she determines that the use of

tracers could improve monitoring of the site and enhance USDW protection from endangerment. The

rule will also allow their use if proposed by the owner or operator and approved by the Director.

Commenter Name: Quinlan J. Shea Letter ID: 0177

Commenter Organization: Edison Electric Institute Comment ID: 23589

Other EPA Comment Codes and Descriptions: 4670 2.6.7 Surface air monitoring and/or soil gas

monitoring (seeking comment) 

Comment: D. Monitoring Provisions and Use of Tracers 

EEI is also concerned about proposed requirements related to monitoring for 

potential CO2 movement and the use of tracers. Under the proposed regulations, 

the UIC program director would have discretion to require the use of tracers or 

surface air/soil gas monitoring "to detect movement of CO2 that could endanger a 

USDW." For the reasons set forth below, EEI is opposed to such a requirement, 

even where, as proposed, it is left to the discretion of the program director. 
- Functionality, usefulness and cost: Tracers are relatively untested in terms 

of workability as a leak-detecting mechanism. Of greater concern, however, is 

the fact that using tracers or surface air or soil gas monitoring would likely 

provide too little information, too late, in terms of providing protection for 

USDW, in the sense that USDW would likely be affected by the time the results of 

such methods revealed any concerns. Moreover, by their very nature, tracers can 

be detected at ultra-low concentrations. If the tracer is spilled or a small 

amount leaked, or if a pipe downstream from the tracer injection point leaked, 

the surface air would become contaminated. Minute amounts of tracer might be 

detectable for quite a distance, making the likelihood of a false positive for 

the tracer much greater without any real benefit to the overall protection of 

USDW. In sum, if employed for purposes of long-term monitoring of underground 

waters, tracers would be unlikely to yield significant useful data and would 

prove extremely expensive. 

- Safety: Tracers may present their own safety concerns depending on the 

precise nature of the tracer at issue. Further, the use of tracers may pose 

independent risks for project operators. There may be potential health effects 

from some tracers if workers are accidentally exposed. 

Response: EPA clarifies that subsurface geochemical and pressure monitoring in the subsurface

formations are the first line of monitoring that would allow detection of potential endangerment to

USDWs from GS activities (this is required at all GS sites, as described at §146.90(d)). The Agency

also believes that surface air and soil gas monitoring, when coupled with subsurface monitoring,

may be appropriate at some GS projects to ensure USDW protection. EPA acknowledges that surface

air and soil gas monitoring may not be suitable in all settings as a method to ensure USDW

protection. However, EPA does not believe that this should entirely preclude their use. The decision

to use surface monitoring and the selection of monitoring methods will be site-specific (e.g., may be

influenced by geology, injection depth, and operational conditions) and must be based on potential

risks to USDWs within the AoR.

The final rule at §146.90(h) retains the allowance for surface air and soil gas monitoring at the

discretion of the Director as a means of identifying leaks that may pose a risk to USDWs and

informing emergency notification of a Class VI owner or operator and UIC Director in the event of a

USDW endangerment, pursuant to requirements at §146.91(c). 

As described above, EPA agrees that tracer use is not appropriate in all situations. EPA

acknowledges that some tracers may have the potential to cause harm to people or the environment.

For this reason, EPA does not require the use of tracers at all GS sites. Nevertheless, there are many

different types of tracers and not all are problematic; research is being done to overcome problems

with existing tracers. EPA believes that tracers have been used safely and successfully in other

applications. Therefore the Director has discretion to require their use if he/she determines that the

use of tracers could improve monitoring of the site and enhance USDW protection from

endangerment. The rule will also allow their use if proposed by the owner or operator and approved

by the Director.

EPA has been following new and ongoing research on the safety and efficacy of tracers, and

believes that, in some circumstances, tracers can be an effective part of monitoring GS projects. EPA

will continue to track research related to tracer use and plans to, every six years, collect and review

data on GS projects to determine whether the appropriate amount and types of information and
appropriate documentation are being collected, and to determine if modifications to the requirements

are appropriate or necessary.

Commenter Name: Quinlan J. Shea Letter ID: 0177

Commenter Organization: Edison Electric Institute Comment ID: 23590

Comment: - Concerns regarding inaccurate public perception: As with a secondary 

containment requirement, a requirement to use tracers--currently unprecedented 

in the UIC program--may create or encourage an overly negative and unwarranted 

public perception regarding the safety of CO2 storage projects. 

Response: EPA believes that tracers can be useful tools for monitoring, plume tracking, and

verification at GS sites and may help improve public confidence in certain projects. Comments

related to whether the use of tracers, if needed, would signal to the public that GS is unsafe are

outside the scope of this rulemaking. However, EPA believes that providing the public with

important information about the project, including how tracers would be an integral part of the site

monitoring plan, will be a key part of improving public acceptance of specific projects and GS

technology in general. 

As described above, the GS rule does not require the use of tracers at all GS sites; however, the

Director has discretion to require their use if he/she determines that the use of tracers could improve

monitoring of the site and enhance USDW protection. The rule will also allow their use if proposed

by the owner or operator and approved by the Director.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23870

Comment: EPA has specifically requested comment on the use of tracers. Based on industry 

experience, tracers are not typically used for monitoring the movement of a CO2 

plume, unless potential leakage is occurring. They are then used to trace the 

leakage point. Tracers can be very expensive and the results can take a lot of 

time to develop, analyze, and understand. Radioactive tracers typically have 

long shelf lives and, if used by neighboring operators, could produce 

conflicting and indeterminate results. Due to the potential for groundwater 

contamination, the use of radioactive materials should be used only sparingly 

and for targeted purposes. 

Response: EPA agrees that tracer use is not appropriate in all Class VI well situations. Some tracers

may have the potential to cause harm to people or the environment. For this reason, EPA does not

require the use of tracers at all GS sites. Nevertheless, there are many different types of tracers and

not all are problematic; research is being done to overcome problems with existing tracers. EPA

believes that tracers have been used safely and successfully in other applications. Therefore the

Director has discretion to require their use if he/she determines that the use of tracers could improve

monitoring of the site and enhance USDW protection from endangerment. The rule will also allow

their use if proposed by the owner or operator and approved by the Director.

EPA has been following new and ongoing research on the safety and efficacy of tracers, and

believes that, in some circumstances, tracers can be an effective part of monitoring GS projects. EPA

will continue to track research related to tracer use and plans to, every six years, collect and review

data on GS projects to determine whether the appropriate amount and types of information and
appropriate documentation are being collected, and to determine if modifications to the requirements

are appropriate or necessary.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23689

Comment: EPA Request for Comment: EPA’s proposal allows Directors’ discretion on whether 

to require the use of tracers, and if so, what types of tracers. EPA seeks 

comment on the use of tracers in CO2 GS operations, and any potential impact of 

tracers on human health or ecosystems as they relate to USDWs. EPA Notice 43513. 

AWWA Response: AWWA recommends that EPA require tracers to be injected along 

with the carbon dioxide stream to provide for a better mechanism of tracking the 

movement of the carbon dioxide plume. Certain tracers could provide for a better 

understanding of the plume behavior using non-traditional indicators, such as 

those that are conservative, easy to measure, non-toxic, and do not degrade into 

contaminants of concern. These tracers could be easily identified in USDWs, as 

well as in the vadose zone, where they could be used as an indicator when carbon 

dioxide soil-gas monitoring proves difficult to interpret. Unfortunately, AWWA 

can not provide recommendations on specific tracers that could be utilized, and 

recommends that EPA perform research, in association with DOE, on the types of 

tracers that would be acceptable for use in carbon sequestration. 

Response: EPA agrees that tracers can be useful tools for monitoring GS projects. EPA also

acknowledges that tracers can also be used to identify (i.e., tag) injections by time, producer, or

location, but clarifies that any requirement for the use of tracers at GS sites would be for the purpose

of identifying potential endangerment to USDWs as a result of CO2 movement from the injection

zone. 

However, EPA does not believe that tracer use is appropriate in all situations. For this reason, EPA

does not require the use of tracers at all GS sites; however, the Director has discretion to require

their use if he/she determines that the use of tracers could improve monitoring of the site and

enhance USDW protection from endangerment. The rule will also allow their use if proposed by the

owner or operator and approved by the Director.

EPA adds that the other aspects of the extensive monitoring required at GS sites, including

monitoring of the well system, tracking of the CO2 plume and pressure front, and geochemical

monitoring, will also detect leaks and track the CO2 plume. 

EPA will continue to track research related to tracer use, and plans to, every six years, collect and

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

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

requirements are appropriate or necessary.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25198

Comment: Z. EPA seeks comment on the use of tracers in CO2 GS operations, and any 

potential impact of tracers on human health or ecosystems as they relate to 
USDWs. 

NYSDEC-DMN Response: Use of tracers in CO2 GS operations should not be routinely 

required although such should be an optional methodology for use at Director 

discretion. The shortcomings of routine use of tracers for GS operations were 

discussed at length at the February 2008 EPA stakeholder workshop. 

Response: EPA agrees that tracer use is not appropriate in all situations. Nevertheless, there are

many different types of tracers and not all are problematic; research is being done to overcome

problems with existing tracers. EPA believes that tracers have been used safely and successfully in

other applications. For this reason, EPA does not require the use of tracers at all GS sites. Rather, the

Director has discretion to require their use if he/she determines that the use of tracers could improve

monitoring of the site and enhance USDW protection from endangerment. The rule will also allow

their use if proposed by the owner or operator and approved by the Director.

EPA has been following new and ongoing research on the safety and efficacy of tracers, and

believes that, in some circumstances, tracers can be an effective part of monitoring GS projects. EPA

will continue to track research related to tracer use and plans to, every six years, collect and review

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

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

are appropriate or necessary.

Commenter Name: Daniel Plath Letter ID: 0188

Commenter Organization: NiSource, Inc. Comment ID: 25236

Comment: 3. Proposed Injection Well Operating Requirements (73 Fed. Reg. at 43512-13) 

The Proposed Rule states that tracers are not mandated to be used but are at the 

Director's discretion to require. Columbia has utilized tracers in several 

fields over the years and has found them to be a useful tool for specific 

applications. It is not, however, a tool that is useful all the time for every 

field. While it is not overly expensive relative to the rest of the facility 

cost, it is a very labor and data intensive application and would represent a 

resource misallocation if mandated by the Final Rule. NiSource believes it would 

be inappropriate to grant the Director the ability to exercise discretion to 

require their use. Instead, we believe it would be much more beneficial to 

simply allow the operator the ability to use tracers at his or her discretion 

when appropriate to address specific situations. 

Response: EPA agrees that tracer use is not appropriate in all situations. For this reason, EPA does

not require the use of tracers at all GS sites; however, the Director has discretion to require their use

if he/she determines that the use of tracers could improve monitoring of the site and enhance USDW

protection from endangerment. The rule will also allow their use if proposed by the owner or

operator and approved by the Director.

EPA has been following new and ongoing research on the safety and efficacy of tracers, including

their efficiency and cost-effectiveness. The Agency plans to, every six years, collect and review data

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

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

are appropriate or necessary.
Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24350

Comment: 7. Tracers 

We strongly oppose any requirement for the use of tracers, including any such 

requirement that could be imposed at the discretion of the Director. 

There are at least two fundamental issues with respect to tracers. First, 

tracers are unlikely to enhance the protection of USDWs. This is true not just 

because the Class VI regulations are designed to minimize the likelihood of the 

kind of leakage tracers would ostensibly help detect, but because - even in the 

event of such a leak - tracers are not likely to be especially useful in leak 

detection (as discussed in the context of monitor wells, fluid monitoring in the 

deep subsurface provides only very localized information and is unlikely be very 

effective in leak detection whether or not tracers are used). Second, tracers 

are at least as likely to create "false positives" as to aid in the detection of 

actual down-hole leaks. The problem in this respect is simple: it is much easier 

for accidental leaks and releases to occur in the surface environment than in 

the deep subsurface. 

A final consideration is perhaps the most obvious: a requirement for tracers 

would be unique in the UIC program, and would unavoidably undermine public 

confidence in permitting determinations that - by definition - would be based on 

the premise that leaks from injection wells and properly permitted injection 

formations are extraordinarily unlikely to occur. 

Response: EPA believes that, in some circumstances, tracers can be an important component of a

multifaceted approach to monitoring GS projects. However, the Agency recognizes that tracers may

not be appropriate in all GS projects. For this reason, EPA does not require the use of tracers at all

GS sites; however, the Director has discretion to require their use if he/she determines that the use of

tracers could improve monitoring of the site and enhance USDW protection from endangerment. 

EPA disagrees that using tracers, where appropriate, would overstate the danger of CO2 or GS.

Rather, EPA believes that providing the public with important information about the project,

including how tracers would be an integral part of the site monitoring plan, will be a key part of

improving public acceptance of specific projects and GS technology in general. 

While the intent of the GS regulations is to prevent leaks of CO2 to USDWs, EPA clarifies that all

of the protective components of the GS regulation, including a comprehensive monitoring program

per §146.90 (which includes testing of the well, ground water quality monitoring, and tracking of the

CO2 plume and pressure front) support a multi-barrier approach to protecting USDWs. Additionally,

some studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005) found that

tracers can provide useful CO2 monitoring information at injection wells both at depth and at nearsurface locations. At Frio, tracers enabled quantification of CO2 plume behavior and provided a

technique for model validity testing (McCallum et al., 2005). EPA will continue to track research

related to tracer use. The Agency plans to, every six years, collect and review data on GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.
Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24534

Comment: Rule Provisions or Federal Register Cite: 73 FR 43513-15 

EPA Preamble Question: 27. EPA’s proposal allows Directors’ discretion on 

whether to require the use of tracers, and if so, what types of tracers. EPA 

seeks comment on the use of tracers in CO2 GS operations, and any potential 

impact of tracers on human health or ecosystems as they relate to USDWs. EPA 

Notice 43513. 

CSC Response: EPA should not mandate the use of tracers. The potential value of 

tracers is uncertain and too limited to justify their use in the injection well 

context. Any use of tracers should be entirely at the option of the operator. 

Response: As described above, EPA agrees that tracer use is not appropriate in all situations. For

this reason, EPA does not require the use of tracers at all GS sites; however, the Director has

discretion to require their use if he/she determines that the use of tracers could improve monitoring

of the site and enhance USDW protection from endangerment. The rule will also allow their use if

proposed by the owner or operator and approved by the Director.

Commenter Name: John R. Baza Letter ID: 0193

Commenter Organization: Utah Division of Oil, Gas, and Mining Comment ID: 23914

Other EPA Comment Codes and Descriptions: 4120 2.4.1.2 Allowing hydraulic fracturing during

GS (seeking comment); 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth 

Comment: Operating Requirements 

EPA seeks comments on hydraulic fracturing, minimum depth requirements, and the 

potential impact of tracer use on human health and the environment. The Division 

concurs with the IOGCC recommendations (included in their December 23, 2008 

comments) that while hydraulic fracturing may be necessary for well completion, 

measures should be taken to prevent any fracturing of the confining zone. No 

minimum depth for GS should be specified and once again should be done on a 

site-specific basis. Use of tracers should be at the discretion of the 

regulating agency. 

Response: The final rule allows the use of hydraulic fracturing at Class VI well sites, where

approved by the Director. Hydraulic fracturing is one of several stimulation technologies available to

improve wellbore and formation injectivity. 

EPA clarifies that all stimulation, including hydraulic fracturing, must be approved by the Director.

Owners or operators must submit a proposed stimulation program as part of the permit application

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

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

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

perform stimulation only as approved. 

The final rule at §146.91(d)(2) also requires that the owner or operator notify the Director 30 days

before performing stimulation during the operational phase of a GS project; this will provide an

additional opportunity for the 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.

In addition, to maintain the integrity of the confining zone, the final rule requires that, except during

stimulation, the injection pressure not exceed 90 percent of the fracture pressure of the injection

zone.

EPA also agrees that it is not appropriate to set a minimum injection depth for GS projects and the

Agency believes that a determination of site-suitability for GS (i.e., that subsurface formations will

receive and confine injected CO2) should be made on a site-specific basis. The GS rule at §146.82

requires the owner or operator to provide extensive site- and project-specific information to the

Director to demonstrate that the site meets the minimum siting criteria at §146.83 and that the CO2

will be contained within the injection formation and that USDWs will be protected from

endangerment. 

EPA acknowledges that there are limited circumstances where injection above the lowermost USDW

can be performed in a manner that protects USDWs, as long as appropriate protections are in place.

The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver

of the Class VI injection depth requirements for injection into non-USDW formations above and/or

between USDWs. The waiver approach requires the submission of extensive, site-specific

information (in conjunction with the permit application submission) to demonstrate that injection of

CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protective

of USDWs. The requirements are designed to ensure that the owner or operator, the Director, and the

Regional Administrator consider, on a site specific basis, the implications, benefits, and challenges

associated with GS and ensuring water availability and USDW protection. For additional information

on the waiver approach, please see the final rule and preamble, as well as EPA's responses to

comments on the Notice of Data Availability and Request for Comment.

Finally, EPA agrees that the use of tracers should not be required at all GS sites, but should be

available as an option. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment. The rule

will also allow their use if proposed by the owner or operator and approved by the Director.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24597

Comment: Rule Provisions: 73 FR 43513- 15 

EPA Rule Issue: 27. EPA’s proposal allows Directors’ discretion on whether to 

require the use of tracers, and if so, what types of tracers. EPA seeks comment 

on the use of tracers in CO2 GS operations, and any potential impact of tracers 

on human health or ecosystems as they relate to USDWs. EPA Notice 43513. 

Anadarko Petroleum Corporation (APC) Response: EPA should not mandate the use of 

tracers. The value of tracers has been questioned by numerous members of the 

scientific community. Further research of their use needs to be conducted before 

any final language is approved. Modeling and monitoring are much more reliable 

techniques for tracking a plume. 

Tracers, in general, provide minimal diagnostic abilities and currently have few 
practical applications. This technology is still under development and as such 

should not be required. Currently, most tracers have the issue of providing 

false positives, have a significant supply time-delay, have greater 

environmental impacts than CO2 (PFCs for instance), and are very expensive. 

Radioactive tracers are utilized the most in operations and prove the most 

useful, but again, only for a limited radius of investigation. Other monitoring 

techniques are more reliable and operational-friendly for tracking the plume and 

determining CO2 migration. While certain tracers can be useful for near-well 

trouble-shooting application this technology on a whole is not ready for fieldwide deployment and any regulation mandating their use should not be instituted. 

Response: EPA agrees that tracer use is not appropriate in all situations. Some tracers may have the

potential to cause harm to people or the environment. Nevertheless, there are many different types of

tracers and not all are problematic; research is being done to overcome problems with existing

tracers. EPA believes that tracers have been used safely and successfully in other applications. For

this reason, EPA does not require the use of tracers at all GS sites; rather, the Director has discretion

to require their use if he/she determines that the use of tracers could improve monitoring of the site

and enhance USDW protection from endangerment. The rule will also allow their use if proposed by

the owner or operator and approved by the Director.

EPA has been following new and ongoing research on the safety and efficacy of tracers, and

believes that, in some circumstances, tracers can be an effective part of monitoring GS projects. EPA

will continue to track research related to tracer use and plans to, every six years, collect and review

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

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

are appropriate or necessary.

Commenter Name: Chris M. Hobson Letter ID: 0201

Commenter Organization: Southern Company Comment ID: 22172

Comment: Southern Company also opposes a requirement for Owners or Operators to use 

tracers in CO2 GS operations. As EPA observes, there are many adverse technical 

and environmental consequences associated with the use of tracers, including the 

possibility of false positives and the release of per fluorocarbon ("PFC") to 

the atmosphere. ¡d. at 43512-13. Southern Company supports the use of tracers in 

the CO2 GS program only if at the option of the Owner or Operator. 

Response: EPA agrees that tracer use is not appropriate in all situations. Some tracers may have the

potential to cause harm to people or the environment. Nevertheless, there are many different types of

tracers and not all are problematic; research is being done to overcome problems with existing

tracers. EPA believes that tracers have been used safely and successfully in other applications. For

this reason, EPA does not require the use of tracers at all GS sites; rather, the Director has discretion

to require their use if he/she determines that the use of tracers could improve monitoring of the site

and enhance USDW protection from endangerment. The rule will also allow their use if proposed by

the owner or operator and approved by the Director.

EPA has been following new and ongoing research on the safety and efficacy of tracers, and

believes that, in some circumstances, tracers can be an effective part of monitoring GS projects. EPA

will continue to track research related to tracer use and plans to, every six years, collect and review

data on GS projects to determine whether the appropriate amount and types of information and
appropriate documentation are being collected, and to determine if modifications to the requirements

are appropriate or necessary.

Commenter Name: Richard Guinn Letter ID: 0210

Commenter Organization: Eastman Chemical Company Comment ID: 22735

Comment: EPA’s proposal allows Directors’ discretion on whether to require the use of 

tracers, and if so, what types of tracers. EPA seeks comment on the use of 

tracers in CO2 GS operations, and any potential impact of tracers on human 

health or ecosystems as they relate to USDWs. EPA Notice 95. 

Tracers should be permitted, but not required. They are commonly and safely used 

in the oil and gas industry. 

Response: EPA agrees that the use of tracers should not be required at all GS sites, but should be

available as an option. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment. The rule

will also allow their use if proposed by the owner or operator and approved by the Director.

Commenter Name: Neeraj Gupta Letter ID: 0229

Commenter Organization: Battelle Energy Technology (BET) Comment ID: 21859

Comment: Page 105, Tracers- We share some of EPA’s concerns about uncertainties in the 

use of Tracers such as PFTs. At the same time these and other tracers have been 

used successfully in many applications in hydrogeology and petroleum geology. 

The current language appears to go too far towards discouraging use of tracers. 

Tracers should not be required for every site however, at the same time their 

use under site-specific situations should not be discouraged. 

Response: EPA agrees that tracers can be useful tools for monitoring GS projects. However, EPA

believes that tracer use is not appropriate in all situations. For this reason, EPA does not require the

use of tracers at all GS sites; however, the Director has discretion to require their use if he/she

determines that the use of tracers could improve monitoring of the site and enhance USDW

protection from endangerment. The rule will also allow their use if proposed by the owner or

operator and approved by the Director. The Director would assess the use of tracers in the context of

site-specific information, including risks to USDWs and other environmental and health risks.

EPA will continue to track research related to tracer use, and plans to, every six years, collect and

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

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

requirements are appropriate or necessary.

Commenter Name: Steven B. Corneli Letter ID: 0234

Commenter Organization: NRG Energy, Inc. Comment ID: 23168

Comment: 3. Tracers 

NRG opposes any requirement to use tracers for leak detection because leaks from 

properly permitted injection wells are not likely to occur. The use of tracers 

will not be effective in the detection of CO2 releases in the subsurface and 
will not ensure the protection of USDWs. Tracers are more likely to cause "false 

positives" by accidental leaks from the equipment on the surface. The Class VI 

regulations are designed to prevent the kind of leakage that the tracers are 

intended to detect. 

Response: EPA believes that, in some circumstances, tracers can be an important component of a

multifaceted approach to monitoring GS projects. However, the Agency recognizes that tracers may

not be appropriate in all GS projects. For this reason, EPA does not require the use of tracers at all

GS sites; however, the Director has discretion to require their use if he/she determines that the use of

tracers could improve monitoring of the site and enhance USDW protection from endangerment. 

While the intent of the GS regulations is to prevent leaks of CO2 to USDWs, EPA clarifies that all

of the protective components of the regulation, including a comprehensive monitoring program per

§146.90 (which includes testing of the well, ground water quality monitoring, and tracking of the

CO2 plume and pressure front) support a multi-barrier approach to protecting USDWs. Additionally,

some studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005) found that

tracers can provide useful CO2 monitoring information at injection wells both at depth and at nearsurface locations. At Frio, tracers enabled quantification of CO2 plume behavior and provided a

technique for model validity testing (McCallum et al., 2005). EPA will continue to track research

related to tracer use. The Agency plans to, every six years, collect and review data on GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

Commenter Name: Robert E. Carter Jr. Letter ID: 0236

Commenter Organization: Indiana Department of Natural Resources (IDNR) Comment ID: 29221

Comment: States like Indiana with a proven track record of effectively managing similar 

programs have indeed demonstrated an ability to adapt to evolving technologies 

and we believe do possess the capability to effectively address long-term 

storage issues. In fact, as indicated earlier in our comments, many of the longterm issues associated with CCGS operations will be outside the purview of the 

UIC Program and will need to be addressed by states as they enact appropriate 

CCGS legislation. EPA should consider implementing rules which afford states 

with the greatest flexibility to select regulatory options that are best suited 

to their specific needs and conditions. Specific examples of requirements that 

may be too prescriptive include: 

6. Any provision requiring the use of down-hole tracer systems. 

Response: EPA agrees that the use of tracers should not be required at all GS sites, but should be

available as an option. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment. The rule

will also allow their use if proposed by the owner or operator and approved by the Director.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23249

Comment: 27. EPA’s proposal allows Directors’ discretion on whether to require the use of 
tracers, and if so, what types of tracers. EPA seeks comment on the use of 

tracers in CO2 GS operations and any potential impact of tracers on human health 

or ecosystems as they relate to USDWs. EPA Notice 43513. 

Discretion on whether to use a tracer is appropriate. Radioactive tracers have 

been successfully utilized in oil and gas operations. The small amount used 

should not threaten human health or USDWs. However, modeling and monitoring are 

generally more appropriate techniques to track a plume since tracers have a 

limited radius of investigation. 

Response: EPA believes that, in some circumstances, tracers can be an important component of a

multifaceted approach to monitoring GS projects. However, the Agency recognizes that tracers may

not be appropriate in all GS projects. For this reason, EPA does not require the use of tracers at all

GS sites; however, the Director has discretion to require their use if he/she determines that the use of

tracers could improve monitoring of the site and enhance USDW protection from endangerment. 

While the intent of the GS regulations is to prevent leaks of CO2 to USDWs, EPA clarifies that all

of the protective components of the regulation, including a comprehensive monitoring program per

§146.90 (which includes testing of the well, ground water quality monitoring, and tracking of the

CO2 plume and pressure front) support a multi-barrier approach to protecting USDWs. Additionally,

some studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005) found that

tracers can provide useful CO2 monitoring information at injection wells both at depth and at nearsurface locations. At Frio, tracers enabled quantification of CO2 plume behavior and provided a

technique for model validity testing (McCallum et al., 2005). EPA will continue to track research

related to tracer use. The Agency plans to, every six years, collect and review data on GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24817

Comment: EPA Notice Questions: 73 FR 43513-15 

EPA Rule Issue: 27. EPA’s proposal allows Directors’ discretion on whether to 

require the use of tracers, and if so, what types of tracers. EPA seeks comment 

on the use of tracers in CO2 GS operations, and any potential impact of tracers 

on human health or ecosystems as they relate to USDWs. EPA Notice 43513. 

GWPC CO2 Committee Response: Due to the knowledge gaps in the use of tracers in 

this type of environment language regarding Directors discretion is OK. However, 

further research needs to be conducted before any final language to allow the 

use of tracers is approved. 

Response: EPA agrees that the use of tracers should not be required at all GS sites, but should be

available as an option. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment. The rule

will also allow their use if proposed by the owner or operator and approved by the Director.
EPA continues to follow new and ongoing research on the safety and efficacy of tracers. For

example, studies at the Frio Brine Pilot Experiment site (Dayton, TX) used various types of tracers,

including perfluorocarbon tracers (PFTs), sulfur hexafluoride, and the noble gases krypton, neon,

and xenon. These studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005)

found that tracers can provide useful CO2 monitoring information at injection wells at depth and at

near-surface locations. At Frio, tracers enabled quantification of CO2 plume behavior and provided a

technique for model validity testing (McCallum et al., 2005). EPA will continue to track research

related to tracer use. 

EPA has been following new and ongoing research on the safety and efficacy of tracers, including

their efficiency and cost-effectiveness. The Agency plans to, every six years, collect and review data

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

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

are appropriate or necessary.

Letter ID: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22813

Comment: III A. 4 Proposed Injection Well Operating Requirements 

BB. EPA seeks comment on the use of tracers in CO2 GS operations, and any 

potential impact of tracers on human health or ecosystems as they relate to 

USDWs. 

IOGCC Response: Adequate down hole monitoring above the containment zone should 

in most cases eliminate the need for tracer systems to detect the presence 

of injected CO2 at the surface. Use of such tracers should not be required 

although should be an optional methodology for use at Director discretion. 

Response: EPA agrees that the use of tracers should not be required at all GS sites, but should be

available as an option. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment. The rule

will also allow their use if proposed by the owner or operator and approved by the Director.

While the intent of the GS regulations is to prevent leaks of CO2 to USDWs, EPA clarifies that all

of the protective components of the regulation, including a comprehensive monitoring program per

§146.90 (which includes testing of the well, ground water quality monitoring, and tracking of the

CO2 plume and pressure front) support a multi-barrier approach to protecting USDWs. Additionally,

some studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005) found that

tracers can provide useful CO2 monitoring information at injection wells both at depth and at nearsurface locations. At Frio, tracers enabled quantification of CO2 plume behavior and provided a

technique for model validity testing (McCallum et al., 2005). EPA will continue to track research

related to tracer use. The Agency plans to, every six years, collect and review data on GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

Commenter Name: Steven Chester Letter ID: 0264
Commenter Organization: Michigan Department of Environmental Quality

(MDEQ)

Comment ID:

22841

Comment: EPA (III . A. 4.) proposes the use of tracers in the injected CO2 to serve as 

warning of leakage. 

-Staff is opposed to allowing tracers. 

Response: EPA agrees that tracer use is not appropriate in all situations. For this reason, EPA does

not require the use of tracers at all GS sites; rather, the Director has discretion to require their use if

he/she determines that the use of tracers could improve monitoring of the site and enhance USDW

protection from endangerment. The rule will also allow their use if proposed by the owner or

operator and approved by the Director.

Commenter Name: Michael Moore Letter ID: 0265

Commenter Organization: North American Carbon Capture & Storage

Association (NACCSA)

Comment ID:

22853

Other EPA Comment Codes and Descriptions: 4670 2.6.7 Surface air monitoring and/or soil gas

monitoring (seeking comment) 

Comment: - Monitoring Provisions/Use of Tracers/Use ofDown-Hole Shut-off Valves: 

NACCSA is opposed to imposition of mandatory requirements to use tracers; conduct 

surface air/soil gas monitoring. 

Response: EPA believes that surface air and soil gas monitoring, when coupled with subsurface

monitoring, may be appropriate at some GS projects to ensure USDW protection. EPA

acknowledges that surface air and soil gas monitoring may not be suitable in all settings as a method

to ensure USDW protection. However, EPA does not believe that this should entirely preclude their

use. The decision to use surface monitoring and the selection of monitoring methods will be sitespecific (e.g., may be influenced by geology, injection depth, and operational conditions) and must

be based on potential risks to USDWs within the AoR.

If surface monitoring were the only monitoring method employed to ensure USDW protection, direct

correlation of CO2 at the surface with CO2 in the subsurface might be difficult; however, when

combined with information gathered through other monitoring techniques required of GS well

owners and operators (e.g., monitoring wells, geophysical techniques), air and soil gas monitoring

may provide valuable data on the magnitude and location of a leak. The CO2 itself may serve as a

tracer in the form of stable isotopes of carbon. For example, anthropogenic CO2 is depleted in 13C

compared to naturally occurring CO2. 

In the final rule, at §146.90(h), the decision to require such monitoring rests with the Director as a

means of identifying leaks that may pose a risk to USDWs and informing emergency notification of

a Class VI owner or operator and UIC Director in the event of a USDW endangerment, pursuant to

requirements at §146.91(c).

EPA believes that, in some circumstances, tracers can be an important component of a multifaceted

approach to monitoring GS projects. However, the Agency recognizes that tracers may not be

appropriate in all GS projects. For this reason, EPA does not require the use of tracers at all GS sites;

however, the Director has discretion to require their use if he/she determines that the use of tracers

could improve monitoring of the site and enhance USDW protection from endangerment.
Commenter Name: Michael Moore Letter ID: 0265

Commenter Organization: North American Carbon Capture & Storage

Association (NACCSA)

Comment ID:

22865

Other EPA Comment Codes and Descriptions: 4670 2.6.7 Surface air monitoring and/or soil gas

monitoring (seeking comment) 

Comment: 4. Monitoring Provisions/Use ofTracers/Use of Down-Hole Shut-off Valves 

The proposed regulations would vest discretion in the program director to 

require the use of tracers and/or surface air/soil gas monitoring "to detect 

movement of CO2 that could endanger a USDW." NACCSA is opposed to this proposed 

requirement for the reasons outlined below. 

The proposal raises potential issues regarding the scope ofEPA's authority. The 

Preamble acknowledges that regulation of surface/atmospheric releases of CO2 is 

outside the scope of the proposed rule and the Agency's jurisdiction under SDWA. 

The UIC program is designed to protect USDW`s from endangerment due to subsurface 

injection. The use of tracers combined with surface or soil monitoring is 

unlikely to be protective because by the time any tracers or CO2 is detected in 

these zones it may have passed through all USDWs between the injection zone and 

the surface. 

NACCSA is also concerned that tracers are relatively untested in terms of leak 

detection capabilities and transport properties. Because there have been limited 

tests of tracers it is not clear how they interact with the subsurface and if they 

are conservatively transported with CO2. Further, tracers may also pose 

independent safety concerns for project operators, workers, and other potentially 

affected individuals and the environment. 

Response: EPA clarifies that use of surface air and soil gas monitoring as specified in the final GS

rule at §146.90(h), as a means of identifying leaks that may pose a risk to USDWs and informing

emergency notification of a Class VI owner or operator and UIC Director in the event of a USDW

endangerment, pursuant to requirements at §146.91(c), is at the Director's discretion.

If surface monitoring were the only monitoring method employed to ensure USDW protection, direct

correlation of CO2 at the surface with CO2 in the subsurface might be difficult; however, when

combined with information gathered through other monitoring techniques required of GS well

owners and operators (e.g., monitoring wells, geophysical techniques), air and soil gas monitoring

may provide valuable data on the magnitude and location of a leak. The CO2 itself may serve as a

tracer in the form of stable isotopes of carbon. For example, anthropogenic CO2 is depleted in 13C

compared to naturally occurring CO2. 

EPA believes that surface air and soil gas monitoring are within the scope of the SDWA in that they

can provide additional data to pinpoint the location and magnitude (or absence) of leaks that could

endanger USDWs. Used in conjunction with deep subsurface monitoring, as required at §146.90, and

as part of a multi-barrier approach to protecting USDWs from endangerment, surface air and soil gas

monitoring are within the scope of SDWA’s general authority (SDWA sections 1421 et al).

Regarding the use of tracers, EPA believes that, in some circumstances, tracers can be an important

component of a multifaceted approach to monitoring GS projects. However, the Agency recognizes

that tracers may not be appropriate in all GS projects. For this reason, EPA does not require the use
of tracers at all GS sites; however, the Director has discretion to require their use if he/she

determines that the use of tracers could improve monitoring of the site and enhance USDW

protection from endangerment. 

While the intent of the GS regulations is to prevent leaks of CO2 to USDWs, EPA clarifies that all

of the protective components of the regulation, including a comprehensive monitoring program per

§146.90 (which includes testing of the well, ground water quality monitoring, and tracking of the

CO2 plume and pressure front) support a multi-barrier approach to protecting USDWs. Additionally,

some studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005) found that

tracers can provide useful CO2 monitoring information at injection wells both at depth and at nearsurface locations. At Frio, tracers enabled quantification of CO2 plume behavior and provided a

technique for model validity testing (McCallum et al., 2005). EPA will continue to track research

related to tracer use. The Agency plans to, every six years, collect and review data on GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

The provision allowing the Director to require the use of tracers and surface air and soil gas

monitoring is within EPA's authority under the SDWA because these methods can provide additional

data to pinpoint the location and magnitude (or absence) of leaks that could endanger USDWs. Used

in conjunction with deep subsurface monitoring, as required at §146.90, and as part of a multibarrier approach to protecting USDWs from endangerment, tracers and surface air and soil gas

monitoring are within the scope of SDWA's general authority (SDWA sections 1421 et al).

Commenter Name: Karl R. Moor Letter ID: 0501

Commenter Organization: Southern Company Comment ID: 21160

Comment: Similarly, on a smaller scale we think as a specific example the EPA should not 

require the use of tracers or soil flux to monitor for possible carbon dioxide 

leaks. Not only are tracers relatively untested when it comes to their ability 

to monitor such leaks, they are also, they also will not transmit sufficiently 

early to provide any sort of real protection to underground sources of water. 

Response: EPA believes that, in some circumstances, tracers can be an important component of a

multifaceted approach to monitoring GS projects. However, the Agency recognizes that tracers may

not be appropriate in all GS projects. For this reason, EPA does not require the use of tracers at all

GS sites; however, the Director has discretion to require their use if he/she determines that the use of

tracers could improve monitoring of the site and enhance USDW protection from endangerment. 

EPA continues to follow new and ongoing research on the safety and efficacy of tracers. For

example, studies at the Frio Brine Pilot Experiment site (Dayton, TX) used various types of tracers,

including perfluorocarbon tracers (PFTs), sulfur hexafluoride, and the noble gases krypton, neon,

and xenon. These studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005)

found that tracers can provide useful CO2 monitoring information at injection wells at depth and at

near-surface locations. At Frio, tracers enabled quantification of CO2 plume behavior and provided a

technique for model validity testing (McCallum et al., 2005). EPA will continue to track research

related to tracer use. 

EPA has been following new and ongoing research on the safety and efficacy of tracers, including

their efficiency and cost-effectiveness. The Agency plans to, every six years, collect and review data
on GS projects to determine whether the appropriate amount and types of information and

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

are appropriate or necessary.

Commenter Name: Doug Louis Letter ID: 0530

Commenter Organization: Kansas Corporation Commission Comment ID: 21345

Comment: Proposed injection well operating requirements. In the proposed rule, EPA is 

seeking comment on the use of tracing material for detection of fugitive CO2. 

KCC staff's opinion is the comparison of baseline CO2 levels to monitored levels 

would provide the same information as would costly and potentially harmful 

tracing material. In our opinion, external mechanical integrity testing at a one 

Response: EPA agrees that tracer use is not appropriate in all situations. Some tracers may have the

potential to cause harm to people or the environment. For this reason, EPA does not require the use

of tracers at all GS sites. Nevertheless there are many different types of tracers and not all are

problematic; research is being done to overcome problems with existing tracers. EPA believes that

tracers have been used safely and successfully in other applications. Therefore the Director has

discretion to require their use if he/she determines that the use of tracers could improve monitoring

of the site and enhance USDW protection from endangerment. The rule will also allow their use if

proposed by the owner or operator and approved by the Director.

If an owner or operator proposes the use of tracers at a GS site, EPA anticipates that the specific

tracers to be used would be described in the testing and monitoring plan, which the Director would

evaluate in the context of other information about the GS site. The Director would assess the use of

tracers in the context of site-specific information, including risks to USDWs and other

environmental and health risks. 

EPA continues to follow new and ongoing research on the safety and efficacy of tracers. For

example, studies at the Frio Brine Pilot Experiment site (Dayton, TX) used various types of tracers,

including PFTs, sulfur hexafluoride, and the noble gases krypton, neon, and xenon. These studies

(e.g., Phelps and Cole, 2008; Hovorka et al. 2005) found that tracers can provide useful CO2

monitoring information at injection wells as well as near-surface locations. At Frio, tracers enabled

quantification of CO2 plume behavior and provided a technique for model validity testing

(McCallum et al., 2005). EPA will continue to track research related to tracer use.

Commenter Name: Mike Moore Letter ID: 0532

Commenter Organization: North American Carbon Capture and Storage

Association (NACCSA)

Comment ID:

21368

Other EPA Comment Codes and Descriptions: 4670 2.6.7 Surface air monitoring and/or soil gas

monitoring (seeking comment) 

Comment: dioxide. Also the director would have discretion without any guidance to require 

tracers and/or gas monitoring to detect movement of carbon dioxide that could 

endanger a USDW. NACSA believes that these methods should not be required 

because there are too many questions about their efficacy and the potential risk 

posed by tracers. 

Response: EPA acknowledges that air and soil gas monitoring are subject to site-specific limitations

and may not be suitable in all settings as a method to ensure USDW protection. However, EPA does
not believe that this should entirely preclude their use. If surface monitoring were the only

monitoring method employed to ensure USDW protection, direct correlation of CO2 at the surface

with CO2 in the subsurface might be difficult; however, when combined with information gathered

through other monitoring techniques required of GS well owners and operators (e.g., monitoring

wells, geophysical techniques), air and soil gas monitoring may provide valuable data on the

magnitude and location of a leak. The CO2 itself may serve as a tracer in the form of stable isotopes

of carbon. For example, anthropogenic CO2 is depleted in 13C compared to naturally occurring

CO2. 

Used in conjunction with deep subsurface monitoring, as required at §146.90, and as part of a multibarrier approach to protecting USDWs from endangerment, surface air and soil gas monitoring will

increase USDW protection, enable immediate notification of the UIC Director in the case of

potential USDW endangerment, and facilitate remedial action.

The decision to use surface monitoring and the selection of monitoring methods will be site-specific

(e.g., may be influenced by geology, injection depth, and operational conditions) and must be based

on potential risks to USDWs within the AoR. The final rule at §146.90(h) retains the allowance for

surface air and soil gas monitoring at the discretion of the Director as a means of identifying leaks

that may pose a risk to USDWs and informing emergency notification of a Class VI owner or

operator and UIC Director in the event of a USDW endangerment, pursuant to requirements at

§146.91(c).

EPA agrees that tracer use is not appropriate in all situations. Some tracers may have the potential to

cause harm to people or the environment. For this reason, EPA does not require the use of tracers at

all GS sites. Nevertheless there are many different types of tracers and not all are problematic;

research is being done to overcome problems with existing tracers. EPA believes that tracers have

been used safely and successfully in other applications. Therefore the Director has discretion to

require their use if he/she determines that the use of tracers could improve monitoring of the site and

enhance USDW protection from endangerment. The rule will also allow their use if proposed by the

owner or operator and approved by the Director.

EPA continues to follow new and ongoing research on the safety and efficacy of tracers. For

example, studies at the Frio Brine Pilot Experiment site (Dayton, TX) used various types of tracers,

including perfluorocarbon tracers (PFTs), sulfur hexafluoride, and the noble gases krypton, neon,

and xenon. These studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005)

found that tracers can provide useful CO2 monitoring information at injection wells at depth and at

near-surface locations. At Frio, tracers enabled quantification of CO2 plume behavior and provided a

technique for model validity testing (McCallum et al., 2005). EPA will continue to track research

related to tracer use. The Agency plans to, every six years, collect and review data on GS projects to

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

Comment Code: 4500 2.5 Proposed Mechanical Integrity Testing (MIT) Requirements (40 CFR

146.89) 

Individual Comments
Commenter Name: John Stormon Letter ID: 0123

Commenter Organization: Washington State Dept. of Ecology Comment ID: 23007

Other EPA Comment Codes and Descriptions: 4630 2.6.3 Corrosion monitoring 

Comment: Periodic corrosion and well integrity testing is important for all pollution 

prevention programs. This well testing will help operators to focus maintenance 

and repair activities on the wells that are degrading. It is far better to 

prevent leakage from a well breach than to fix the well after discovering that 

it has leaked. 

Response: EPA agrees with the commenter; the final rule requires both internal and external

mechanical integrity testing. Mechanical integrity testing is one of the cornerstones of the existing

EPA UIC program. The MIT requirements at §146.89, along with the corrosion monitoring required

at §146.90(c), ensure protection of USDWs from endangerment and provide an important early

warning of potential problems in the injection well. Routine mechanical integrity testing of injection

wells provides data that enables the identification and remediation of well integrity problems before

they lead to leakage and/or endangerment of USDWs. For additional information, please see the

discussion of MITs in the final rule preamble.

EPA also agrees that corrosion monitoring is appropriate given the potentially corrosive nature of the

CO2 stream. CO2 in the presence of water becomes acidic, potentially accelerating corrosion of well

materials. The CO2 stream for a GS project may also contain small volumes of impurities that could

contribute to corrosion. For these reasons, the final rule requires quarterly corrosion monitoring (at

§146.90(c)).

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22561

Comment: Wellbore Integrity Monitoring and Measurement 

The integrity of monitoring and injection wells must be established and 

monitored. However, the type of integrity measurement(s) should be decided upon 

based on the construction of the well, the well materials, and the effectiveness 

of the monitoring techniques. Wells that are not cemented from total depth (TD) 

to the surface should be subject to more integrity monitoring than those that 

are cemented from TD to surface because the path behind the uncemented section 

of casing could act as a fast path for fluids to move between formations. No 

single specific monitoring technique should be required and it is expected that 

multiple techniques will be needed. The deviation of all wells should be 

measured to ensure that the geometry of the well is understood to identify areas 

that may require special attention, like poorly centralized sections, to ensure 

that they are carefully characterized. 

A requirement will be needed to ensure that the integrity and quality of the 

casing and cement job are initially and remain sufficient to prevent fluid 

movement along the wellbore. Because the cement is behind the casing, it will 

be necessary to use some type of logging tool to make the measurement. The 

selection of logging tools should be based on proven performance. The 

prescription of a particular tool may force the use of a technology in the 

future that is not the best available for the job. This said, the standard for 

selection of the tool can be specified and should take into account the geometry 
of a wellbore. Because wells are cylindrical, the integrity and location of the 

cement must be verified using technology capable of radially evaluating and 

mapping the cement, identifying the location of channels or contaminated cement, 

and validating the casing-cement and cement-formation bonds, thus providing a 

360° map of the cement and any potential defects for the entire length of the 

cemented casing. 

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 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, per §146.90. Owners or operators should develop a plan that is

appropriate to the well’s design and construction; the Director will evaluate the plan based on

construction plans submitted with the permit application.

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 at §146.89(e). For additional information, please see the

discussion of MITs in the final rule preamble.

EPA agrees with the commenter that the integrity and location of the cement must be verified using

technology capable of radially evaluating and mapping the cement. For this reason, owners or

operators must, during construction, perform a cement bond and variable density log to evaluate

cement quality radially, and a temperature log after the casing is set and cemented (146.87(a)(2)(ii)).

In addition, EPA is using an adaptive approach to regulating GS. The Agency plans to collect and

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

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

the requirements are appropriate or necessary.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23867

Comment: E. MECHANICAL INTEGRITY TESTING REQUIREMENTS 

EPA would require owners and operators of Class VI projects to monitor internal 

mechanical integrity of their injection wells by continuously monitoring 

injection pressure, flow rate, and injected volumes, as well as the annular 

pressure and fluid volume to assure that no anomalies occur that may indicate an 

internal leak. The practicability of such monitoring is yet unknown. The 

proposed MIT requirements, therefore, should be flexible. The same holds true 

for the frequency of internal and external MITs for injection wells, the types 

of MITs, and how to optimize MIT methods for geologic sequestration. As industry 

gains more knowledge and experience, more structured regulations for MIT types 

and frequency of MITs may be appropriate. 

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

integrity of Class VI wells as required under §146.89(b), instead of periodic testing (which is

required for most other types of deep injection wells) is important given the potential corrosive
impact of CO2 and impurities on well materials, the potential geomechanical impacts to well

integrity due to CO2 phase changes, and the temperature and pressure effects associated with

injecting supercritical CO2. EPA also believes that the technology for continuous monitoring is

practicable, available, and is currently in fairly wide use. The Texas Class I well regulations for

industrial wells currently require continuous monitoring of annulus pressure and volume and the

majority of injection wells in Ohio conduct continuous monitoring (GWPC, 2006). At least one

commenter indicated that the technology required for continuous monitoring is currently available

and should not present an undue cost burden. Continuous annulus monitoring is also conducted at

the commercial-scaled carbon capture and geologic sequestration operation at the In Salah, Algeria

natural gas plant where more than 3 million tons of CO2 have been sequestered since 2004.

EPA believes that the annual mechanical integrity testing is appropriate for GS wells. EPA retains

the requirement that owners or operators of Class VI wells demonstrate injection well external

mechanical integrity at least once annually. See §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.

The Agency plants to collect and review data every six years on GS projects to determine whether

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

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

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23876

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: EPA defines "mechanical integrity" as "the absence of significant leakage within 

the injection tubing, casing, or packer (known as internal mechanical 

integrity), or outside of the casing (known as external mechanical integrity)." 

The term "significant leakage" is not defined. An overly broad interpretation 

could result in a finding that mechanical integrity is not being maintained, 

notwithstanding the absence of any leakage that calls into question the safety 

of the project or threatens USDWs. EPA should characterize what constitutes 

"significant" or clarify under what conditions significant leakage might be 

construed. We suggest defining and construing the term within the statutorily 

defined concept of "endangerment"[FN52] under SDWA, i.e., significant leakage 

would be defined as any leakage that could potentially endanger a USDW. The 

amount of leakage and what constitutes significant may vary depending upon the 

geologic formations and proximity to USDWs.[FN53] 

[FN52] Endangerment is defined as follows: 

Underground injection endangers drinking water sources if such injection 

may result in the presence in underground water which supplies or can 

reasonably be expected to supply any public water system of any 

contaminant, and if the presence of such contaminant may result in such 

system's not complying with any national primary drinking water 
regulation or may otherwise adversely affect the health of persons. 32 

U.S.C. $ 300h(d). 

[FN53] Miami-Dade County. EPA, 529 F.3d 1049 (11th Cir. 2008) (upholding 

EPA's rule eliminating the non-endangerment finding requirement for Class I 

municipal injection wells). 

Response: A properly designed and operated well should have no leakage in the casing, tubing, or

packer and no fluid movement into a USDW through channels adjacent to the wellbore. While the

intent of MITs is to detect these types of problems as early as possible, the goal of the well design

and construction requirements at §146.86 is the complete absence of such problems. EPA clarifies

that the purpose of the "significant leakage" language in this narrow context is simply to avoid

triggering corrective actions for essentially de minimis situations. Determining whether a MIT result

should trigger follow-up action is necessarily a case and site-specific situation; as a result, EPA does

not believe it is appropriate to define the term "significant leakage" in the context of MITs. In

addition, EPA has not defined this term for purposes of other injection well classes and this has not

been shown to hinder permitting authorities' and owners or operators' ability to assess whether

injection wells have adequate mechanical integrity. EPA believes that this approach allows states

flexibility, will not interfere with the implementation of existing UIC programs, and maintains

protection of USDWs from endangerment. 

In keeping with its adaptive rulemaking approach, the Agency plans to collect and review data every

six years on early 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. For additional information, please see

the discussion of MITs in the final rule preamble.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23686

Other EPA Comment Codes and Descriptions: 2060 1.5.3 Comments on grandfathering of

existing wells (seeking comment) 

Comment: constructed with this appurtenance. Also, some of the potentially grandfathered 

wells may not be constructed in a way that would allow for the mechanical 

integrity testing requirements that are part of the regulation. AWWA believes 

that some of the very prescriptive testing and monitoring requirements are 

necessary, as the grandfathered wells may not have been constructed in a way 

that would allow for these tests to be carried out. AWWA recommends that EPA 

include in the final regulation a requirement that the owners/operators of the 

wells conclusively prove that the grandfathered wells can be operated in 

compliance with all the other requirements of the proposed regulation or the 

wells will not be permitted for Class VI operation. 

Response: EPA agrees with the commenter regarding the need for MITs; the final rule requires both

internal and external mechanical integrity testing. Mechanical integrity testing is one of the

cornerstones of the existing EPA UIC program. MIT requirements at §146.89 ensure protection of

USDWs from endangerment and provide an important early warning of potential problems in the

injection well. Routine mechanical integrity testing of injection wells provides data that enables the

identification and remediation of well integrity problems before they lead to leakage and/or

endangerment of USDWs. 
EPA agrees that a cautious approach to grandfathering is appropriate, particularly given that the

converted well will be used for a substantially different process. The final GS rule provides for the

construction of these wells to be grandfathered (per 146.81(c)). EPA has included a requirement in

the final GS rule that owners or operators seeking to convert existing wells for long term storage

must demonstrate to the Director that the grandfathered wells were engineered and constructed meet

the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at

§146.86(b) and §146.87(a). EPA clarifies that only the construction requirements are grandfathered

and that all other Class VI requirements (reporting, monitoring, mechanical integrity testing, etc.)

must be met following a determination under §146.81(c). 

EPA adds that following re-permitting as Class VI wells, these projects would be subject to the

requirements of the final GS rule, including MIT, monitoring, operational, reporting, plugging, and

post-injection site care and site closure requirements. See the discussion of EPA's final regulatory

approach in the preamble to the GS rule for additional detail on these requirements.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23696

Other EPA Comment Codes and Descriptions: 4600 2.6 Proposed Plume and Pressure Front

Monitoring Requirements (40 CFR 146.90) 

Comment: Category: Monitoring 

EPA Request for Comment: EPA’s proposal would require owners or operators of 

Class VI GS projects to monitor internal mechanical integrity of their injection 

wells by continuously monitoring injection pressure, flow rate, and injected 

volumes, as well as the annular pressure and fluid volume to assure that no 

anomalies occur that may indicate an internal leak. EPA requests comment on the 

practicability of this requirement. EPA Notice 43513. 

EPA seeks comment on the appropriate frequency of internal and external MITs for 

GS injection wells, the appropriate types of MITs, and how to optimize MIT 

methods for GS. EPA Notice 43514. 

EPA seeks comment on the requirement for monitoring of GS sites for the purpose 

of tracking the location of the CO2 plume and associated pressure front over 

time. EPA Notice 43514 

EPA’s proposal would require that owners or operators perform a pressure falloff test at least once every five years. EPA seeks comment on the use and 

frequency of pressure fall-off testing for GS wells. EPA Notice 43515. 

Specifically, EPA seeks comment regarding the usefulness of indirect geophysical 

monitoring and surface air and soil gas monitoring. In addition, EPA seeks 

comment regarding the use of a Director-approved monitoring plan for GS sites. 

EPA Notice 43517. 

AWWA Response: Detailed monitoring guidelines were developed as part of a joint 

research project by AwwaRF and AWWA. These guidelines are provided in Section 

III of these comments and EPA should include the named tests and frequencies in 
the final regulation to ensure that protection of USDWs is consistent across all 

geologic sequestration projects. Based upon these requirements, owner/operators 

would develop testing and monitoring plans, which should be reviewed and updated 

at the same time as the re-evaluation of the Area of Review. The costs 

associated with monitoring of a sequestration project should not be a major 

consideration when determining the types and frequency of required monitoring. 

The goal of the monitoring requirements should be on preventing degradation of 

USDWs, not minimizing the cost to the owner/operator. 

AWWA strongly recommends both that both internal and external mechanical 

integrity testing should be required to prevent leakage of carbon dioxide from 

the injection well. Monitoring of the plume and pressure front over time is 

absolutely required as part of the system operation and a project shouldn't even 

be considered unless this monitoring is included. All of the monitoring 

Response: EPA agrees with the commenter; the final rule requires both internal and external

mechanical integrity testing. Mechanical integrity testing is one of the cornerstones of the existing

EPA UIC program. MIT requirements at §146.89 ensure protection of USDWs from endangerment

and provide an important early warning of potential problems in the injection well. Routine

mechanical integrity testing of injection wells provides data that enables the identification and

remediation of well integrity problems before they lead to leakage and/or endangerment of USDWs.

The GS rule's requirements for MITs encompass many of the same tests mentioned in the AwwaRF

and AWWA monitoring guidelines, including an approved tracer log, or noise logs and temperature

logs. EPA believes that the MITs described in the rule at §146.89(c) are effective methods to

demonstrate external MI. They have been used successfully by injection well operators for decades

and provide an important early warning of potential problems in the injection well system. While the

oxygen activation log is not explicitly required in the rule, the regulations do provide flexibility at

§146.89(e) to allow the Director to require additional test methods or, with the approval of the

Administrator, to approve the use of alternative MIT methods. These additional methods could

include the annual pressure test recommended in the AwwaRF/AWWA guidelines. The specific

MITs required prior to start-up of injection or at well workovers would be identified in the permit by

the Director. For additional information, please see the discussion of MITs in the final rule preamble.

As stated above, EPA disagrees that the rule should specify the monitoring techniques for all GS

sites. 

EPA agrees that tracking the plume and the position of the pressure front during injection operations

and the post-injection site care period will provide important data for determining that the injectate is

confined within the target formation, as well as for evaluating any risks within the AoR. EPA also

agrees with the commenter that data collected during site characterization (such as baseline

geochemistry, pre-injection reservoir pressure, etc.) are appropriate to ensure that there is a baseline

with which to compare GS operation and post-injection data. 

EPA is developing guidance on testing and monitoring to assist owners or operators and Directors in

evaluating requirements under §146.90, including proposed monitoring plans. The guidance

describes recommended approaches for implementing a testing and monitoring plan, including preoperational 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 final GS rule. 

EPA also agrees that periodic updates to the plan are appropriate. EPA clarifies that the final GS

regulation includes a requirement that the AoR be reevaluated every 5 years, and it specifies at

§146.90(j) that the operator revise the testing and monitoring plan to incorporate the results of the

most recent AoR reevaluation and recent operational and monitoring data.

EPA clarifies that cost-benefit analyses are not used to determine the most appropriate monitoring

technologies, location, or frequency. Instead, the Agency believes that the flexibility afforded the

owner or operator at §146.90 to develop a testing and monitoring plan tailored to site-specific

characteristics is appropriate for GS.

Commenter Name: Thomas Curtis Letter ID: 0181

Commenter Organization: American Water Works Association (AWWA) Comment ID: 23742

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Part 146.89(f) AWWA recommends revising this part to read: 

The Director may require additional or alternative tests if the results 

presented by the owner or operator under paragraph (d) of this section are not 

satisfactory to the Director to demonstrate that there is no significant leak in 

the casing, tubing or packer or significant movement of fluid into or between 

USDWs, or between the injection zone(s) and USDWs, resulting from the injection 

activity as stated in paragraphs (a)(1) and (2) of this section. 

Response: EPA clarifies that the regulations at §146.89(e) 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. 

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. 

In addition, EPA is using an adaptive approach to regulating GS. The Agency plans to collect and

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

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

the requirements are appropriate or necessary.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24351

Comment: F. Mechanical Integrity Testing (MIT) Requirements 

The proposed rule suggests that "MIT requirements for GS wells should be 

tailored to address the unique properties of CO2, specifically its buoyancy and 
potential corrosivity." 73 Fed. Reg. at 43513. As previously discussed, however, 

the buoyancy of CO2 is a relatively trivial factor in relation to the cone of 

influence created by injection pressure during injection, a factor that makes 

buoyancy virtually irrelevant as a driving force for upward migration through 

the injection well borehole during the operational life of a GS well. 

Accordingly, there is no basis to suggest that the buoyancy of CO2 is a 

significant factor to consider in establishing mechanical integrity testing 

requirements for GS wells. Similarly - as also previously discussed - CO2 is not 

corrosive and cannot be expected to cause substantial corrosion problems for the 

injection well (including down-hole cement) unless the CO2 stream itself 

contains water. Consequently, concerns related to corrosion do not justify 

particularly stringent MIT requirements for GS wells. 

Experience with CO2 in the EOR context fully supports these conclusions. In 

fact, the Class II MIT requirements have been sufficient for CO2 injection in 

the EOR/EGR context, and there is no reason why they should not be sufficient in 

the GS context as well. Accordingly, the proposed MIT requirements for Class VI 

wells are more stringent and prescriptive than necessary. 

Response: EPA disagrees with this comment. EPA has identified buoyancy as one of the unique

characteristics of CO2 that warrants special consideration. The Agency believes that buoyancy of the

injected CO2 coupled with other characteristics of GS operations, including the large injection

volumes and timeframes of storage, present operating circumstances at Class VI wells that are

different from other classes of wells and associated injectates regulated by the UIC Program. 

Supercritical CO2 has a lower density than the native formation fluids in the target injection

formations typically anticipated for GS. Once injected, the more buoyant CO2 will have a tendency

to migrate upwards. This expected movement is similar to the situation found in some Class I wells

(see Revision to the Federal UIC Requirements for Class I--Municipal Wells in Florida; 65 FR

42234, July 7, 2000). Well monitoring in Florida identified upward fluid movement from some Class

I municipal wells attributed to the lower density of the injection fluid (in this case due to lower TDS)

compared to the native formation fluids. The injection fluids rose to the top of the injection zone

preferentially through fractures. Such migration could occur through conduits in the injection

wellbore as well as in the target formations. In the case of GS, any cracks or fractures in the cement

casing for a GS injection well would also serve as conduits for upward migration of more buoyant

fluids. External MITs, which test for movement along the borehole, are therefore appropriate

requirements for GS wells. 

EPA disagrees that the MIT requirements for Class VI wells are excessive. MITs are a long-standing

and proven method of providing early warning of potential problems in the injection well system

before they lead to leakage and/or endangerment of USDWs. 

EPA also disagrees that corrosivity is not a concern. While some studies of cement performance

have shown encouraging results, other information gathered through research and field data provided

in the rulemaking docket, show evidence of chemical alteration and suggest a potential for

degradation to occur and potentially endanger USDWs. Although laboratory and field studies

suggest that corrosion problems may not be severe, such problems cannot be conclusively ruled out.

Laboratory exploration of cement alteration and degradation is an ongoing research area, and fieldbased studies are very few. There also does not appear to be a clear consensus on the corrosion risks

for the steel components of injection wells. Given the anticipated long lifespan of Class VI wells and
the difficulties that would be associated with a corrosion-related well failure, EPA believes that the

MIT requirements at §146.89 are justified.

A comprehensive review of MIT results found that Class I wells injecting corrosive fluids fail MITs

at rates two to three times higher than those that inject non-corrosive fluids (USEPA, 1999). Given

the potential for CO2 to be corrosive (when in the presence of water), there is a potential risk factor

for MIT failure and the tailored MIT requirements are appropriate. 

EPA agrees that Class II well operators have decades of experience injecting CO2. However, EPA

believes that significant operational differences exist between Class II and Class VI wells. For

example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than

for Class II wells. Also, reservoir pressure conditions will be different with ER production

(extraction) serving to reduce reservoir pressure for Class II operations while Class VI injection

operations will have no comparable de-pressuring activities. For these reasons, EPA believes that

injection of CO2 for GS warrants more frequent MITs to provide sufficient early warning of the

potential for MI failures due to the corrosivity of the CO2 or reservoir pressure conditions associated

with CO2 GS. 

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24474

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.89(a) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Response: EPA acknowledges the comment and the final rule retains the text at 146.89(a) as

proposed.

Commenter Name: Jeff W. Sheets Letter ID: 0192

Commenter Organization: ConocoPhillips Comment ID: 23895

Comment: - The Mechanical Integrity Testing (MIT) requirements: In addition to daily 

monitoring of pressure, API recommends that: 

At least once per year, the owner or operator must confirm the absence 

of significant fluid movement under paragraph (a)(2) of this section 

using a method acceptable to the Director (e.g. including diagnostic 

surveys such as oxygen-activation logging or temperature or noise 

logs). 

Revised text supports a performance-based approach and allows the 

development and use of new technologies as they become available. 

Subsection (3) was deleted because it requires the tubing to be pulled 

at significant cost and risk of uncontrolled releases. 

Response: EPA believes that the MITs described in §146.89(c) of the rule (an approved tracer log or
temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for decades. The

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

approve the use of alternative MIT methods, which can allow the use of any new technologies that

become available. 

In addition, EPA is using an adaptive approach to regulating GS. The Agency plans to collect and

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

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

the requirements are appropriate or necessary.

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind

the casing, but clarifies that it can be used to determine the presence or absence of corrosion of the

long-string casing, and is required if the Director determines that it is necessary based on sitespecific information. EPA has revised the final GS rule to require that the frequency of the casing

inspection log must be specified in the approved testing and monitoring plan. See §146.89(d). 

Commenter Name: John King Letter ID: 0211

Commenter Organization: Shell Exploration and Production Company

(SEPCo)

Comment ID:

22749

Other EPA Comment Codes and Descriptions: 3820 2.3.1 Well construction procedures 

Comment: - The Class VI requirements addressing issues such as well construction and 

mechanical integrity testing should be no different than the Class II 

requirements. 

Response: EPA disagrees with the commenter and believes that significant operational differences

between Class II wells and Class VI wells indicate that the Class II requirements are not sufficient to

address the differences and that Class VI MIT requirements are, therefore, appropriate. For example,

the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class

II wells. Also, reservoir pressure conditions will be different with ER production (extraction) serving

to reduce reservoir pressure for Class II operations while Class VI injection operations will have no

comparable de-pressuring activities. For these reasons, EPA believes that injection of CO2 for GS

projects differs significantly from that of Class II ER operations and warrants more frequent MITs to

provide sufficient early warning of the potential for MI failures due to the corrosivity of the CO2 or

reservoir pressure conditions associated with CO2 GS. For additional information, please see the

discussion of MITs in the final rule preamble.

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

every six years on early 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.

Commenter Name: John King Letter ID: 0211

Commenter Organization: Shell Exploration and Production Company

(SEPCo)

Comment ID:

22775

Other EPA Comment Codes and Descriptions: 2046 1.5.2.3 Continuing to classify CO2 injection

for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment) 
Comment: E. Mechanical Integrity Testing (MIT) Requirements 

The proposed rule suggests, "MIT requirements for GS wells should be tailored to 

address the unique properties of CO2, specifically its buoyancy and potential 

corrosivity." 73 Fed. Reg. at 43513. As previously discussed, however, the 

buoyancy of CO2 is a relatively trivial factor in relation to the cone of 

influence created by injection pressure during injection, a factor that makes 

buoyancy virtually irrelevant as a driving force for upward migration through 

the injection well borehole during the operational life of a GS well. 

Accordingly, there is no basis to suggest that the buoyancy of CO2 is relevant 

to be considered in establishing mechanical integrity testing requirements for 

GS wells. Similarly -- as also previously discussed -- CO2 is not corrosive and 

cannot be expected to cause corrosion problems for the injection well (including 

down-hole cement) unless the CO2 stream itself contains water. Consequently, 

corrosion generally should not be expected to be a problem and concerns related 

to corrosion do not justify any particularly stringent requirements for GS 

wells. Experience with CO2 in the EOR context fully supports these conclusions. 

In fact, the Class II MIT requirements have been sufficient for CO2 injection in 

the EOR/EGR context, and there is no reason why they should not be sufficient in 

the GS context as well. 

Response: EPA disagrees with this comment. EPA has identified buoyancy as one of the unique

characteristics of CO2 that warrants special consideration. The Agency believes that buoyancy of the

injected CO2 coupled with other characteristics of GS operations, including the large injection

volumes and timeframes of storage, present operating circumstances at Class VI wells that are

different from other classes of wells and injectates regulated by the UIC Program. 

Supercritical CO2 has a lower density than the native formation fluids in the target injection

formations typically anticipated for GS. Once injected, the more buoyant CO2 will have a tendency

to migrate upwards. This expected movement is similar to the situation found in some Class I wells

(see Revision to the Federal UIC Requirements for Class I--Municipal Wells in Florida; 65 FR

42234, July 7, 2000). Well monitoring in Florida identified upward fluid movement from some Class

I municipal wells attributed to the lower density of the injection fluid (in this case due to lower TDS)

compared to the native formation fluids. The injection fluids rose to the top of the injection zone

preferentially through fractures. Such migration could occur through conduits in the injection

wellbore as well as in the target formations. In the case of GS, any cracks or fractures in the cement

casing for a GS injection well would also serve as conduits for upward migration of more buoyant

fluids. External MITs, which test for movement along the borehole, are therefore appropriate

requirements for GS wells. 

EPA disagrees that the MIT requirements for Class VI wells are excessive. MITs are a long-standing

and proven method of providing early warning of potential problems in the injection well system

before they lead to leakage and/or endangerment of USDWs. 

EPA also disagrees that corrosivity is not a concern. While some studies of cement performance

have shown encouraging results, other information gathered through research and field data provided

in the rulemaking docket, show evidence of chemical alteration and suggest a potential for

degradation to occur and potentially endanger USDWs. Although laboratory and field studies

suggest that corrosion problems may not be severe, such problems cannot be conclusively ruled out.
Laboratory exploration of cement alteration and degradation is an ongoing research area, and fieldbased studies are very few. There also does not appear to be a clear consensus on the corrosion risks

for the steel components of injection wells. Given the anticipated long lifespan of Class VI wells and

the difficulties that would be associated with a corrosion-related well failure, EPA believes that the

MIT requirements at §146.89 are justified.

A comprehensive review of MIT results found that Class I wells injecting corrosive fluids fail MITs

at rates two to three times higher than those that inject non-corrosive fluids (USEPA, 1999). Given

the potential for CO2 to be corrosive (when in the presence of water), there is a potential risk factor

for MIT failure and the tailored MIT requirements are appropriate. 

EPA agrees that Class II well operators have decades of experience injecting CO2. However, EPA

believes that significant operational differences exist between Class II and Class VI wells. For

example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than

for Class II wells. Also, reservoir pressure conditions will be different with ER production

(extraction) serving to reduce reservoir pressure for Class II operations while Class VI injection

operations will have no comparable de-pressuring activities. For these reasons, EPA believes that

injection of CO2 for GS warrants more frequent MITs to provide sufficient early warning of the

potential for MI failures due to the corrosivity of the CO2 or reservoir pressure conditions associated

with CO2 GS. 

Commenter Name: Darrick Eugene Letter ID: 0223

Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23987

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: 7. § 146.89 Mechanical integrity. 

EPA Proposed §146.89(c) At least once per year, the owner or operator 

must use one of the following methods to determine the absence of 

significant fluid movement under paragraph (a)(2) of this section: 

(3) A casing inspection log, if required by the Director. 

Among the test protocols prescribed by the proposed rule to confirm lack of 

significant fluid movement is a casing inspection log. Although this log is 

optional, it may be required by the Director. Conducting a casing inspection log 

will require the tubing to be pulled from a well, and that in turn substantially 

increases the possibility of a well control event (that is a loss of control 

over well operation). Accordingly, the technique should only be mandated when 

other testing methodologies are unavailable. TxCCSA suggests the following edit: 

§146.89(c) At least once per year, the owner or operator must use one of 

the following methods to determine the absence of significant fluid 

movement under paragraph (a)(2) of this section: 

(3) A casing inspection log, if A TRACER SURVEY OR A TEMPERATURE OR 

NOISE LOG CANNOT BE OBTAINED AND A CASING INSPECTION LOG IS THUS 

required by the Director. 

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

movement behind the casing, but clarifies that it is a technique that can be used to determine the
presence or absence of corrosion of the long-string casing, and is required if the Director determines

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

that the frequency of the casing inspection log be specified in the approved testing and monitoring

plan at §146.89(d).

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21692

Comment: With regard to validating mechanical integrity of CO2 injection wells, HEI 

generally agrees with EPA’s suggestion to evaluate the "absence of significant 

leaks" by monitoring at some regular frequency the injection pressure, flow 

rate, injected volumes and the annular pressure. (See §146.89 (b).) An 

alternative method for determining mechanical integrity, as noted by EPA, is 

periodic pressure testing; this should remain an option for site-specific cases. 

Where periodic pressure testing is implemented, the pressure should be 

considered by evaluation of the formation potential instead of casing burst or 

tubing collapse limit. 

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

integrity as required under §146.89(b) is preferable to periodic pressure testing as a means of

demonstrating internal MI. The combination of computer-driven continuous pressure monitoring

linked to an automatic injection shut-off system provides maximum protection to USDWs from

endangerment and is the earliest warning to owners or operators that well repairs need to be

performed. EPA believes that the technology for continuous monitoring is available, is currently in

fairly wide use. The Texas Class I well regulations for industrial wells currently require continuous

monitoring of annulus pressure and volume and the majority of injection wells in Ohio conduct

continuous monitoring (GWPC, 2006). At least one commenter indicated that the technology

required for continuous monitoring is currently available and should not present an undue cost

burden. Continuous annulus monitoring is also conducted at the commercial-scaled carbon capture

and geologic sequestration operation at the In Salah, Algeria natural gas plant where more than 3

million tons of CO2 have been sequestered since 2004. 

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

every six years on early 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.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21743

Comment: With regard to validating mechanical integrity of CO2 injection wells, BP 

generally agrees with EPA’s suggestion to evaluate the "absence of significant 

leaks" by monitoring at some regular frequency the injection pressure, flow 

rate, injected volumes and the annular pressure. (See § 146.89 (b).) An 

alternative method for determining mechanical integrity, as noted by EPA, is 

periodic pressure testing; this should remain an option for site-specific cases. 

Where periodic pressure testing is implemented, the pressure should be 

considered by evaluation of the formation potential instead of casing burst or 

tubing collapse limit. 
Response: EPA believes that continuous pressure monitoring to demonstrate internal mechanical

integrity as required under §146.89(b) is preferable to periodic pressure testing as a means of

demonstrating internal MI. The combination of computer-driven continuous pressure monitoring

linked to an automatic injection shut-off system provides maximum protection to USDWs from

endangerment and is the earliest warning to owners or operators that well repairs need to be

performed. EPA believes that the technology for continuous monitoring is available, is currently in

fairly wide use. The Texas Class I well regulations for industrial wells currently require continuous

monitoring of annulus pressure and volume and the majority of injection wells in Ohio conduct

continuous monitoring (GWPC, 2006). At least one commenter indicated that the technology

required for continuous monitoring is currently available and should not present an undue cost

burden. Continuous annulus monitoring is also conducted at the commercial-scaled carbon capture

and geologic sequestration operation at the In Salah, Algeria natural gas plant where more than 3

million tons of CO2 have been sequestered since 2004. 

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

every six years on early 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.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24915

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.89 

EPA Proposal: 9. Mechanical integrity 

(a) A Class VI well has mechanical integrity if: 

(1) There is no significant leak in the casing, tubing or packer; and 

(2) There is no significant fluid movement into a USDW through channels adjacent 

to the injection well bore. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Response: EPA acknowledges the comment and the final rule retains the text at 146.89(a) as

proposed. For additional information, please see the discussion of MITs in the final rule preamble.

Letter ID: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22814

Comment: III A. 5 Proposed Mechanical Integrity Testing Requirements 

CC. EPA requests comment on the practicability of this requirement. 

IOGCC Response: The IOGCC believes that the methodologies and requirements under 

Class II would be sufficient for Class VI wells and that applying Class I 
requirements is too stringent. 

Response: EPA disagrees that the MIT requirements for Class VI wells are excessive. MITs are a

long-standing and proven method of providing early warning of potential problems in the injection

well system before they lead to leakage and/or endangerment of USDWs. 

Given the unique nature of CO2 injection for GS (i.e., the potential corrosivity 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 CO2 and the potential for its movement up a wellbore),

EPA believes it is important to protect USDWs from endangerment by adopting MIT requirements

that are tailored to CO2 injection for GS.

A comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that Class I

wells injecting corrosive fluids fail MITs at rates two to three times higher than those that inject noncorrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (when in the presence

of water or aqueous formation fluids), there is a potential risk factor for MIT failure and, for this

reason, EPA believes that the tailored MIT requirements are appropriate. For additional information,

please see the discussion of MITs in the final rule preamble.

EPA acknowledges and agrees with the commenter that Class II well operators have decades of

experience injecting CO2. However, EPA believes that significant operational differences between

Class II wells and Class VI wells indicate that the Class II requirements are not sufficient to address

the differences and that Class VI MIT requirements are, therefore, appropriate. For example, the

volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II

wells. Also, reservoir pressure conditions will be different with ER production (extraction) serving to

reduce reservoir pressure for Class II operations while Class VI injection operations will have no

comparable de-pressuring activities. For these reasons, EPA believes that injection of CO2 for GS

projects differs significantly from that of Class II ER operations and warrants more frequent MITs to

provide sufficient early warning of the potential for MI failures due to the corrosivity of the CO2 or

reservoir pressure conditions associated with CO2 GS. 

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

every six years on early 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.

Commenter Name: William Herz Letter ID: 0266

Commenter Organization: The Fertilizer Institute Comment ID: 22883

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: Definition of "Significant Leakage" 

TFI requests that EPA define the term "significant leakage" in the context 

of mechanical integrity testing and quantify amounts to avoid misinterpretations 

and to prevent de minimus CO2 leakage from falling under this term. 

Response: A properly designed and operated well should have no leakage in the casing, tubing, or

packer and no fluid movement into a USDW through channels adjacent to the wellbore. While the

intent of MITs is to detect these types of problems as early as possible, the goal of the well design

and construction requirements at §146.86 is the complete absence of such problems. EPA clarifies
that the purpose of the "significant leakage" language in this narrow context is simply to avoid

triggering corrective actions for essentially de minimis situations. Determining whether a MIT result

should trigger follow-up action is necessarily a case and site-specific situation; as a result, EPA does

not believe it is appropriate to define the term "significant leakage" in the context of MITs. In

addition, EPA has not defined this term for purposes of other injection well classes and this has not

been shown to hinder permitting authorities' and owners or operators' ability to assess whether

injection wells have adequate mechanical integrity. EPA believes that this approach allows states

flexibility, will not interfere with the implementation of existing UIC programs, and maintains

protection of USDWs from endangerment. 

In keeping with its adaptive rulemaking approach, the Agency plans to collect and review data every

six years on early 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. For additional information, please see

the discussion of MITs in the final rule preamble.

Commenter Name: Donn Miller Letter ID: 0270

Commenter Organization: State of Oregon, Water Resources Department Comment ID: 22888

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: 146.89 Mechanical Integrity. 

This rule uses the term "significant" in a number of places when describing 

leaks. There should be either a definition of "significant" or the wells should 

be adequately sealed so that there are no leaks. 

Response: A properly designed and operated well should have no leakage in the casing, tubing, or

packer and no fluid movement into a USDW through channels adjacent to the wellbore. While the

intent of MITs is to detect these types of problems as early as possible, the goal of the well design

and construction requirements at §146.86 is the complete absence of such problems. EPA clarifies

that the purpose of the "significant leakage" language in this narrow context is simply to avoid

triggering corrective actions for essentially de minimis situations. Determining whether a MIT result

should trigger follow-up action is necessarily a case and site-specific situation; as a result, EPA does

not believe it is appropriate to define the term "significant leakage" in the context of MITs. In

addition, EPA has not defined this term for purposes of other injection well classes and this has not

been shown to hinder permitting authorities' and owners or operators' ability to assess whether

injection wells have adequate mechanical integrity. EPA believes that this approach allows states

flexibility, will not interfere with the implementation of existing UIC programs, and maintains

protection of USDWs from endangerment. 

In keeping with its adaptive rulemaking approach, the Agency plans to collect and review data every

six years on early 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. For additional information, please see

the discussion of MITs in the final rule preamble.

Commenter Name: Cynthia Lane Letter ID: 0528

Commenter Organization: American Water Works Association (AWWA) Comment ID: 21389

Other EPA Comment Codes and Descriptions: 4546 2.5.2.2 MIT frequency (seeking comment) 
Comment: We believe that the mechanical integrity testing requirements are well developed 

in the rule and that the one year time period that is required will provide for 

the protection of USDW's. 

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

approved tracer log or temperature or noise logs) are effective methods to demonstrate external MI,

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 for the UIC

Program for decades. For additional information, please see the discussion of MITs in the final rule

preamble.

EPA also believes that annual MITs are 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.

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

Individual Comments

Commenter Name: Michael H. Cochran Letter ID:

0108

Commenter Organization: Bureau of Water, Division of Environment, Kansas

Department of Health & Environment (KDHE)

Comment

ID: 21979

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

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

pressure above the normal operating pressure so that potential problems are 

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

operation of the well 

Response: EPA believes that continuous pressure monitoring to demonstrate internal MI at

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

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

wells, is necessary given the potential corrosive impact of CO2 in the presence of water and

impurities on well materials, the potential geomechanical impacts to well integrity due to CO2 phase

changes, and the temperature and pressure effects associated with injecting supercritical CO2. The

regulation, at §146.89(e), provides the Director the discretion to require an annual annulus pressure

MIT in addition to the continuous pressure monitoring to demonstrate internal MI; such a periodic

pressure test could serve as an additional safeguard.

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24793

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule
language; 4720 2.7.2 Operational recordkeeping and reporting 

Comment: (b) To evaluate the absence of significant leaks under paragraph (a)(1) of 

this section, owners or operators must, following an initial annulus pressure 

test, continuously monitor injection pressure, rate, injected volumes, and 

pressure on the annulus between tubing and long stem casing and annulus fluid 

volume as specified in §146.88(e);

{Redundant language.} 

Response: The final rule retains this text to provide clarity about requirements for demonstrating

internal mechanical integrity and to specify the necessary monitoring. EPA believes that continuous

pressure monitoring to demonstrate internal mechanical integrity of Class VI wells (146.89(b)),

instead of periodic testing (which is required for most other types of deep injection wells) is

important given the potential corrosive impact of CO2 and impurities on well materials, the potential

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

pressure effects associated with injecting supercritical CO2.

For additional information, please see the discussion of MITs in the final rule preamble.

Commenter Name: Carl Carlsson Letter ID: 0131

Commenter Organization: SUEZ Energy Generation NA, LLC Comment ID: 21535

Comment: Mechanical Integrity Testing 

SEGNA agrees with EPA's proposal to require continuous downhole monitoring, 

as the required technology is currently available and should not present an undue 

cost when required on new wells. However, SEGNA is opposed to requiring 

Response: EPA acknowledges the comment and believes that continuous pressure monitoring to

demonstrate internal mechanical integrity of Class VI wells required at §146.89(b), instead of

periodic testing, which is required for most other types of deep injection wells is important given the

potential corrosive impact of CO2 and impurities on well materials, the potential geomechanical

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

associated with injecting supercritical CO2. For additional information, please see the discussion of

MITs in the final rule preamble.

Commenter Name: Bonnie Lovelace Letter ID: 0152

Commenter Organization: Montana Department of Environmental Quality

(MDEQ)

Comment ID:

22117

Comment: 16. EPA seeks comment on monitoring of internal mechanical integrity on injection 

wells. MDEQ believes that such monitoring is appropriate. Injection wells would 

be in place for a very long time and could even be used in the future to mine 

the carbon dioxide and sell it as a commodity. Further, as technology advances, 

such wells maybe available for reactivation even if closed. Integrity ofthe 

structure of the well is paramount to the ongoing and future use. 

Response: EPA acknowledges the comment and believes that continuous pressure monitoring to

demonstrate internal mechanical integrity of Class VI wells required at §146.89(b), instead of

periodic testing, which is required for most other types of deep injection wells is important given the

potential corrosive impact of CO2 and impurities on well materials, the potential geomechanical
impacts to well integrity due to CO2 phase changes, and the temperature and pressure effects

associated with injecting supercritical CO2. For additional information, please see the discussion of

MITs in the final rule preamble.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24186

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4720 2.7.2 Operational recordkeeping and reporting 

Comment: Rule Provision: 146.89(b) 

API Comments: (b) To evaluate the absence of significant leaks under paragraph 

(a)(1) of this section, owners or operators must, following an initial annulus 

pressure test, continuously monitor AND RECORD AT LEAST DAILY, ANNULUS PRESSURE 

AND VOLUMES OF PACKER FLUID INJECTED OR REMOVED FROM injection pressure, rate,

injected volumes, and pressure on the annulus between THE tubing and long 

stem STRING casing and annulus fluid volume as specified in §146.88 (e);

Rationale: Technical clarification. 

Response: EPA agrees with the commenter regarding the importance of demonstrating internal

mechanical integrity (MI), but disagrees with the suggested changes. Class VI injection wells must

be equipped with dedicated computer-based continuous pressure monitoring devices in concert with

the shut-off systems required for GS wells, which typically take readings several times per second

(i.e., more frequently than daily) and record them electronically in a computer system. See §146.88.

For additional information, please see the discussion of MITs in the final rule preamble.

EPA also disagrees that it is necessary to report volumes of packer fluid injected or removed. EPA

agrees with the commenter that recording annulus fluid volume may not be appropriate. EPA

believes that knowing annulus fluid volume (146.88(e)) is a necessary component of monitoring well

mechanical integrity, but believes that knowing the annulus fluid volume added is sufficient to meet

the intent of the requirement. The final GS rule requires that owners or operators use continuous

recording devices to monitor injection pressure, rate, and volume, as well as the pressure on the

annulus between the tubing and the long string casing. It also modifies the requirement in the

proposed rule to continuously monitor annulus fluid volume; it now requires recording of annulus

fluid volume added. See §§146.88(e); 146.89(b); and 146.90 (b). 

The final rule includes the suggested change from “long-stem” to “long-string” casing.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24243

Comment: Rule Provisions: 146.89(b) 

EPA Preamble Question: 28. EPA’s proposal would require owners or operators of 

Class VI GS projects to monitor internal mechanical integrity of their injection 

wells by continuously monitoring injection pressure, flow rate, and injected 

volumes, as well as the annular pressure and fluid volume to assure that no 

anomalies occur that may indicate an internal leak. EPA requests comment on the 

practicability of this requirement. EPA Notice 43513. 
API Response: There is concern regarding what constitutes continuous monitoring. 

Industry agrees that regular monitoring of the parameters identified by EPA is 

appropriate. Our experience with CO2 EOR strongly shows that daily monitoring of 

most of these parameters is adequate (exceptions to this would be on a sitespecific basis). Recording should generally be done on a daily basis and 

reporting on a semiannually basis. As a guiding principle, the frequency of 

monitoring should be determined by the level of risk posed by the injection 

operation. 

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

integrity of Class VI wells required under §146.89(b), instead of periodic testing, which is required

for most other types of deep injection wells, is important given the potential corrosive impact of CO2

and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2

phase changes, and the temperature and pressure effects associated with injecting supercritical CO2.

EPA also believes that the technology for continuous monitoring is available and is currently in

fairly wide use. EPA anticipates that Class VI injection wells will be equipped with dedicated

computer-based continuous pressure monitoring devices (in concert with the shut-off systems

required for GS wells), which typically take readings several times per second (i.e., more frequently

than daily) and record them electronically in a computer system. 40 CFR 146.91(a)(2) requires that

monthly averages of the continuous annulus monitoring be reported on a semiannual basis. 

At least one commenter indicated that the technology required for continuous monitoring is currently

available and should not present an undue cost burden. Continuous annulus monitoring is also

conducted at the commercial-scale carbon capture and geologic sequestration operation at the In

Salah, Algeria natural gas plant where more than 3 million tons of CO2 have been sequestered since

2004.

EPA acknowledges that additional data on GS is needed and is using an adaptive approach to

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

determine whether the appropriate amount and types of information and appropriate documentation

are being collected, and to determine if modifications to the requirements are appropriate or

necessary.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25199

Other EPA Comment Codes and Descriptions: 4200 2.4.2 Down-hole shut-off valves in GS wells

(seeking comment) 

Comment: III A. 5 Proposed Mechanical Integrity Testing Requirements 

AA. EPA requests comment on the practicability of this requirement. 

NYSDEC-DMN Response: NYSDEC-DMN supports EPA’s proposal to require operators of 

GS projects to monitor internal mechanical integrity by continuously monitoring 

injection pressure, flow rate, and injected volumes, as well as annular pressure 

and fluid volume to provide early detection of anomalies that may indicate an 

internal leak. However, an "alarm" should shut in the well at the surface rather 

than requiring the installation and use of a downhole shut-off valve. 
Response: EPA acknowledges the comment and believes that continuous pressure monitoring to

demonstrate internal mechanical integrity of Class VI wells required at §146.89(b), instead of

periodic testing, which is required for most other types of deep injection wells is important given the

potential corrosive impact of CO2 and impurities on well materials, the potential geomechanical

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

associated with injecting supercritical CO2. For additional information, please see the discussion of

MITs in the final rule preamble.

To meet the requirements at §146.88(e), Class VI wells will be equipped with some type of

continuous computer-based monitoring device that will be connected to alarms and the shut-off

system. EPA does not believe it is necessary to specify what type of equipment is to be used to

trigger the shut-off system. Instead, the regulation allows the owner or operator some flexibility in

deciding what equipment and alarms should be installed to allow site specific flexibility and to make

use of improvements in technology. The technology for continuous monitoring is available and is

currently in fairly wide use. The combination of computer-driven continuous pressure monitoring

linked to an automatic injection shut-off provides maximum protection of USDWs from

endangerment and provides the earliest warning to owners or operators that well repairs need to be

performed.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25200

Other EPA Comment Codes and Descriptions: 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: BB. EPA seeks comment on the appropriate frequency of internal and external MITs 

for GS injection wells, the appropriate types of MITs, and how to optimize MIT 

methods for GS. 

NYSDEC-DMN Response: As stated above, NYSDEC-DMN supports continuous monitoring 

of internal mechanical integrity for GS injection wells. For external MITs, the 

frequency should be more or less annually depending upon the specific 

circumstances. The types of tests allowed should be those appropriate under the 

specific circumstances. 

Response: EPA agrees with commenter regarding the importance of demonstrating internal

mechanical integrity (MI). The final GS rule retains the requirement for continuous pressure

monitoring of Class VI wells to demonstrate internal mechanical integrity and annual external MITs.

EPA believes that the annual external mechanical integrity testing is appropriate for GS wells. EPA

retains the requirement that owners or operators of Class VI wells demonstrate injection well

external mechanical integrity at least once annually. See §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 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 clarifies that the regulations at §148.89(e) 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. For additional information, please see the discussion of MITs

in the final rule preamble.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24346

Comment: 3. Continuous Monitoring 

As already indicated, we support continuous annulus and injection pressure 

monitoring for leak detection purposes. Continuous monitoring of injection rate, 

volume, and injectate temperature is also appropriate, but the proposed 

requirement for continuous monitoring of annulus fluid volume is unnecessary and 

(depending on what is actually contemplated) impractical. There is ample UIC 

program experience demonstrating that continuous monitoring of annulus fluid 

volume is not required for any purpose. For leak detection, pressure monitoring 

- with periodic records of annulus fluid additions and withdrawals - has proved 

to be sufficient. 

Response: EPA acknowledges the comment and agrees that continuous pressure monitoring to

demonstrate internal mechanical integrity required under §146.89(b) is important given the potential

corrosive impact of CO2 and impurities on well materials, the potential geomechanical impacts to

well integrity due to CO2 phase changes, and the temperature and pressure effects associated with

injecting supercritical CO2. The final GS rule retains this requirement. 

EPA acknowledges that recording annulus fluid volume may not always be appropriate. EPA

believes that knowing annulus fluid volume as required at §146.88(e) is a necessary component of

monitoring well mechanical integrity, but believes that knowing the annulus fluid volume added is

sufficient to meet the intent of the requirement. The final GS rule requires that owners or operators

use continuous recording devices to monitor injection pressure, rate, and volume; as well as the

pressure on the annulus between the tubing and the long string casing. It also modifies the

requirement in the proposed rule to continuously monitor annulus fluid volume; it now requires

recording of annulus fluid volume added. See §§146.88(e); 146.89(b); and 146.90 (b). 

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24352

Comment: As already indicated, we support the requirement for continuous injection and 

annulus pressure monitoring as a means to ensure "internal" mechanical 

integrity. With regard to "external" mechanical integrity, we believe that the 

Response: EPA agrees with the commenter regarding the importance of demonstrating internal

mechanical integrity (MI), required under §146.89(b). EPA believes that continuous pressure

monitoring of GS wells, instead of periodic testing (which is required for most other types of deep

injection wells), is appropriate because the potentially corrosive nature of CO2 injectate streams in
the presence of water enables the immediate identification of corrosion-related internal mechanical

integrity problems that could lead to significant well problems and failure. The final GS rule retains

this requirement.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24475

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4720 2.7.2 Operational recordkeeping and reporting 

Comment: Rule Provision: 146.89(b) 

Proposed CCS Group Recommendations: (b) To evaluate the absence of significant 

leaks under paragraph (a)(1) of this section, owners or operators must, 

following an initial annulus pressure test, continuously monitor AND RECORD AT 

LEAST DAILY, ANNULUS PRESSURE AND VOLUMES OF FLUID ADDED TO OR

REMOVED FROM 

injection pressure, rate, injected volumes, and pressure on the annulus 

between the tubing and long stem string casing and annulus fluid volume as 

specified in §146.88 (e);

Basis for CCS Group Comments: We recommend continuous monitoring, but do not 

find continuous recording necessary as Class II requirements have proven 

sufficient. The alternative of continuous monitoring, which will alert operator 

to any problems, and daily recording to allow for daily check of wells. This is 

consistent with successful Class II operating experience. 

Response: EPA agrees with the commenter regarding the importance of demonstrating internal

mechanical integrity (MI). Class VI injection wells will be equipped with dedicated computer-based

continuous pressure monitoring devices, in concert with the shut-off systems required for GS wells,

which typically take readings several times per second (i.e., more frequently than daily) and record

them electronically in a computer system. 40 CFR §146.91(a)(2) requires that monthly averages of

the continuous annulus monitoring be reported on a semiannual basis.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24535

Comment: Rule Provisions or Federal Register Cite: 146.89(b) 

EPA Preamble Question: 28. EPA’s proposal would require owners or operators of 

Class VI GS projects to monitor internal mechanical integrity of their injection 

wells by continuously monitoring injection pressure, flow rate, and injected 

volumes, as well as the annular pressure and fluid volume to assure that no 

anomalies occur that may indicate an internal leak. EPA requests comment on the 

practicability of this requirement. EPA Notice 43513. 

CSC Response: There is concern regarding what constitutes continuous monitoring. 

Industry agrees that regular monitoring of the parameters identified by EPA is 

appropriate. Our experience with CO2 EOR strongly shows that daily monitoring of 

most of these parameters is adequate (exceptions to this would be on a sitespecific basis). Recording should generally be done on a daily basis and 

reporting on a semi-annual basis. As a guiding principle, the frequency of 
monitoring should be determined by the level of risk posed by the injection 

operation. 

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

integrity of Class VI wells required at §146.89(b), instead of periodic testing (which is required for

most other types of deep injection wells), is important given the potential corrosive impact of CO2

and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2

phase changes, and the temperature and pressure effects associated with injecting supercritical CO2.

EPA also believes that the technology for continuous monitoring is practicable, available, and is

currently in fairly wide use. At least one commenter indicated that the technology required for

continuous monitoring is currently available and should not present an undue cost burden.

Continuous annulus monitoring is also conducted at the commercial-scaled carbon capture and

geologic sequestration operation at the In Salah, Algeria natural gas plant where more than 3 million

tons of CO2 have been sequestered since 2004.

Class VI injection wells will be equipped with dedicated computer-based continuous pressure

monitoring devices (in concert with the shut-off systems required for GS wells), which typically take

readings several times per second (i.e., more frequently than daily) and record them electronically in

a computer system. 40 CFR §146.91(a)(2) requires that monthly averages of the continuous annulus

monitoring be reported on a semiannual basis.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24598

Comment: Rule Provisions: 146.89(b) 

EPA Rule Issue: 28. EPA’s proposal would require owners or operators of Class VI 

GS projects to monitor internal mechanical integrity of their injection wells by 

continuously monitoring injection pressure, flow rate, and injected volumes, as 

well as the annular pressure and fluid volume to assure that no anomalies occur 

that may indicate an internal leak. EPA requests comment on the practicability 

of this requirement. EPA Notice 43513. 

Anadarko Petroleum Corporation (APC) Response: There is concern regarding what 

constitutes continuous monitoring. Anadarko agrees that regular monitoring of 

the parameters identified by EPA is appropriate. Our experience with CO2 EOR 

strongly shows that daily monitoring of most of these parameters is adequate 

(exceptions to this would be on a site-specific basis). Recording should 

generally be done on a daily basis and reporting on a semiannual basis. As a 

guiding principle, the frequency of monitoring should be determined by the level 

of risk posed by the injection operation and should be set on a case-by-case 

basis at the permit approval stage taking into consideration the site-specific 

characteristics of the proposed project. 

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

integrity of Class VI wells (146.89(b)), instead of periodic testing (which is required for most other

types of deep injection wells) is important given the potential corrosive impact of CO2 and

impurities on well materials, the potential geomechanical impacts to well integrity due to CO2 phase

changes, and the temperature and pressure effects associated with injecting supercritical CO2. EPA

also believes that the technology for continuous monitoring is practicable, available, and is currently

in fairly wide use. At least one commenter indicated that the technology required for continuous
monitoring is currently available and should not present an undue cost burden. Continuous annulus

monitoring is also conducted at the commercial-scaled carbon capture and geologic sequestration

operation at the In Salah, Algeria natural gas plant where more than 3 million tons of CO2 have been

sequestered since 2004.

Class VI injection wells must be equipped with dedicated computer-based continuous pressure

monitoring devices in concert with the shut-off systems required for GS wells, which typically take

readings several times per second (i.e., more frequently than daily) and record them electronically in

a computer system. 40 CFR §146.91(a)(2) requires that monthly averages of the continuous annulus

monitoring be reported on a semiannual basis. For additional information, please see the discussion

of MITs in the final rule preamble.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24698

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4720 2.7.2 Operational recordkeeping and reporting 

Comment: Rule Provision: 146.89(b) 

Anadarko Petroleum Corporation (APC) Comments: (b) To evaluate the absence of 

significant leaks under paragraph (a)(1) of this section, owners or operators 

must, following an initial annulus pressure test, continuously monitor AND 

RECORD AT LEAST DAILY, ANNULUS PRESSURE AND VOLUMES OF PACKER FLUID

INJECTED OR 

REMOVED FROM injection pressure, rate, injected volumes, and pressure on the 

annulus between THE tubing and long stem STRING casing and annulus fluid 

volume as specified in §146.88 (e);

Rationale: Technical clarification. 

Response: EPA agrees with the commenter regarding the importance of demonstrating internal

mechanical integrity (MI), but disagrees with the suggested changes. Class VI injection wells will be

equipped with dedicated computer-based continuous pressure monitoring devices in concert with the

shut-off systems required for GS wells, which typically take readings several times per second (i.e.,

more frequently than daily) and record them electronically in a computer system. 40 CFR

§146.91(a)(2) requires that monthly averages of the continuous annulus monitoring be reported on a

semiannual basis.

40 CFR §146.91(a)(2) requires that monthly averages of the continuous annulus monitoring be

reported on a semiannual basis. EPA agrees with the commenter that recording annulus fluid volume

may not be appropriate. EPA believes that annulus fluid volume (146.88(e)) is a necessary

component of monitoring well mechanical integrity, but believes that knowing the annulus fluid

volume added is sufficient to meet the intent of the requirement. The final GS rule requires that

owners or operators use continuous recording devices to monitor injection pressure, rate, and

volume, as well as the pressure on the annulus between the tubing and the long string casing. It also

modifies the requirement in the proposed rule to continuously monitor annulus fluid volume; it now

requires recording of annulus fluid volume added. See §§146.88(e), 146.89(b), and 146.90 (b). The

final rule implements the suggested change from “long-stem” to “long-string” casing.
Commenter Name: Ronald Evans Letter ID: 0215

Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24305

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Furthermore, the requirement to continuously monitor the annulus fluid volume is 

impractical, because it does not provide any meaningful data regarding potential 

problems with the operation of the well. Requiring the continuous monitoring of 

the amount of annulus fluid added during operations is more practical and will 

reveal potential leakage paths. Denbury recommends the following: 

§146.88(e) The owner or operator must install and use continuous 

recording devices to monitor: The injection pressure; the rate, volume, 

and temperature of the carbon dioxide stream; and the pressure on the 

annulus between the tubing and the long string casing and THE VOLUME OF 

annulus fluid added to the annulus volume; and the owner 

or operator must install and use alarms and automatic down-hole

shut-off systems, designed to alert the operator and shut-in off 

the well when operating parameters such as annulus pressure, injection 

rate or other parameters approved by the Director diverge beyond 

permitted ranges and/or gradients specified in the permit. IF THE 

Response: EPA believes that monitoring of annulus fluid volume is an important method for

verifying that the well system is intact and is necessary for monitoring annulus pressure. While this

requirement has, until now, been limited to Class I hazardous waste injection wells, the high

volumes and supercritical nature of the injectate, the potential geomechanical stresses in the

wellbore, and the potential for movement of the buoyant CO2 in the event of a MI loss make it an

important safety consideration for GS projects. Continuous pressure monitoring allows immediate

identification of corrosion-related well integrity loss. EPA agrees with the commenter that recording

annulus fluid volume may not be appropriate. EPA believes that knowing annulus fluid volume as

required at §146.88(e) is a necessary component of monitoring well mechanical integrity, but also

believes that knowing the annulus fluid volume added is sufficient to meet the intent of the

requirement. The final GS rule requires that owners or operators use continuous recording devices to

monitor injection pressure, rate, and volume, as well as the pressure on the annulus between the

tubing and the long string casing. It also modifies the requirement in the proposed rule to

continuously monitor annulus fluid volume; it now requires recording of annulus fluid volume

added. See §§146.88(e); 146.89(b); and 146.90 (b).

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21693

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: The frequency of the monitoring should be defined not as "continuous" but as 

"regular" or "periodic" based upon site characteristics because regular 

monitoring (e.g., every minute or hour) will often be adequate. For example, 

fluid volume in the annulus is static and requires evaluation of a pressure 

pulse to determine the depth of top of fluid. Therefore, this should be 

monitored on a monthly or quarterly basis to support the pressure data. 

Response: EPA believes that continuous pressure monitoring of GS wells, instead of periodic
testing, which is required for most other types of deep injection wells is appropriate because the

potentially corrosive nature of CO2 injectate streams in the presence of water enables the immediate

identification of corrosion-related internal mechanical integrity problems that could lead to

significant well problems and failure. Continuous monitoring was found to be very important in an

EPA study of UIC Class I internal MIT failure rates and causes (USEPA 1993). The study reviewed

MIT results over a 5 year period and found 135 MIT failures in 428 wells (a single well can have

more than one MIT failure). In all cases, the MIT failures were found through continuous annulus

monitoring which served the important role of an early warning to prevent any well failure. Class VI

injection wells must be equipped with dedicated computer-based continuous pressure monitoring

devices in concert with the shut-off systems required for GS wells, which typically take readings

several times per second and record them electronically in a computer system. 40 CFR §146.91(a)(2)

requires that monthly averages of the continuous annulus monitoring be reported on a semiannual

basis. 

EPA believes that monitoring of annulus fluid volume is an important method for verifying that the

well system is intact, and knowing the annulus fluid volume is necessary for monitoring annulus

pressure. While this requirement has until now been limited to Class I hazardous waste injection

wells, the high volumes and supercritical nature of the injectate, the potential geomechanical stresses

in the wellbore, and the potential for movement of the buoyant CO2 in the event of a MI loss make it

an important safety consideration for GS projects. Continuous pressure monitoring allows immediate

identification of corrosion-related well integrity loss. EPA agrees with the commenter that recording

annulus fluid volume may not be appropriate. However, EPA believes that knowing annulus fluid

volume required at §146.88(e) is a necessary component of monitoring well mechanical integrity,

but believes that knowing the annulus fluid volume added is sufficient to meet the intent of the

requirement. The final GS rule requires that owners or operators use continuous recording devices to

monitor injection pressure, rate and volume; as well as the pressure on the annulus between the

tubing and the long string casing. It also modifies the requirement in the proposed rule to

continuously monitor annulus fluid volume; it now requires recording of annulus fluid volume added

§§146.88(e); 146.89(b); and 146.90 (b). 

Fluid level can be detected using acoustic techniques (Schubert, 1998). The Texas Class I well

regulations for industrial wells currently require continuous monitoring of annulus pressure and

volume, and the majority of injection wells in Ohio conduct continuous monitoring (GWPC, 2006).

At least one commenter indicated that the technology required for continuous monitoring is currently

available and should not present an undue cost burden. Continuous annulus monitoring is also

conducted at the commercial-scaled carbon capture and geologic sequestration operation at the In

Salah, Algeria natural gas plant where more than 3 million tons of CO2 have been sequestered since

2004. The technology for continuous monitoring is available, is currently in fairly wide use, and the

costs are not burdensome, especially given the operational and safety considerations addressed.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21744

Comment: The frequency of the monitoring should be defined not as "continuous" but as 

"regular" or "periodic" based upon site characteristics because regular 

monitoring (e.g., every minute or hour) will often be adequate. For example, 

fluid volume in the annulus is static and requires evaluation of a pressure 

pulse to determine the depth of top of fluid. Therefore, this should be 

monitored on a monthly or quarterly basis to support the pressure data. 
Response: EPA believes that continuous pressure monitoring of GS wells, instead of periodic

testing, which is required for most other types of deep injection wells is appropriate because the

potentially corrosive nature of CO2 injectate streams in the presence of water enables the immediate

identification of corrosion-related internal mechanical integrity problems that could lead to

significant well problems and failure. Continuous monitoring was found to be very important in an

EPA study of UIC Class I internal MIT failure rates and causes (USEPA 1993). The study reviewed

MIT results over a 5 year period and found 135 MIT failures in 428 wells (a single well can have

more than one MIT failure). In all cases, the MIT failures were found through continuous annulus

monitoring which served the important role of an early warning to prevent any well failure. Class VI

injection wells must be equipped with dedicated computer-based continuous pressure monitoring

devices in concert with the shut-off systems required for GS wells, which typically take readings

several times per second and record them electronically in a computer system. 40 CFR §146.91(a)(2)

requires that monthly averages of the continuous annulus monitoring be reported on a semi-annual

basis. 

EPA believes that monitoring of annulus fluid volume is an important method for verifying that the

well system is intact, and knowing the annulus fluid volume is necessary for monitoring annulus

pressure. While this requirement has until now been limited to Class I hazardous waste injection

wells, the high volumes and supercritical nature of the injectate, the potential geomechanical stresses

in the wellbore, and the potential for movement of the buoyant CO2 in the event of a MI loss make it

an important safety consideration for GS projects. Continuous pressure monitoring allows immediate

identification of corrosion-related well integrity loss. EPA agrees with the commenter that recording

annulus fluid volume may not be appropriate. However, EPA believes that knowing annulus fluid

volume as specified at §146.88(e) is a necessary component of monitoring well mechanical integrity,

but believes that knowing the annulus fluid volume added is sufficient to meet the intent of the

requirement. The final GS rule requires that owners or operators use continuous recording devices to

monitor injection pressure, rate and volume; as well as the pressure on the annulus between the

tubing and the long string casing. It also modifies the requirement in the proposed rule to

continuously monitor annulus fluid volume; it now requires recording of annulus fluid volume

added. See §§146.88(e); 146.89(b); and 146.90(b). 

Fluid level can be detected using acoustic techniques (Schubert, 1998). The Texas Class I well

regulations for industrial wells currently require continuous monitoring of annulus pressure and

volume, and the majority of injection wells in Ohio conduct continuous monitoring (GWPC, 2006).

At least one commenter indicated that the technology required for continuous monitoring is currently

available and should not present an undue cost burden. Continuous annulus monitoring is also

conducted at the commercial-scaled carbon capture and geologic sequestration operation at the In

Salah, Algeria natural gas plant where more than 3 million tons of CO2 have been sequestered since

2004. The technology for continuous monitoring is available, is currently in fairly wide use, and the

costs are not burdensome, especially given the operational and safety considerations addressed.

Commenter Name: Steven B. Corneli Letter ID: 0234

Commenter Organization: NRG Energy, Inc. Comment ID: 23167

Comment: 2. Continuous Monitoring 

NRG supports continuous monitoring of the annular and injection pressure for 

well integrity purposes. However, the proposed requirement for continuous 

monitoring of the annular fluid volume is impractical and unnecessary. We 

recommend continuous measurement of the annular pressure as a means of leak 
detection instead of the annual fluid volume. 

Response: EPA believes that monitoring of annulus fluid volume is an important method for

verifying that the well system is intact, and knowing the annulus fluid volume is necessary for

monitoring annulus pressure. While this requirement has until now been limited to Class I hazardous

waste injection wells, the high volumes and supercritical nature of the injectate, the potential

geomechanical stresses in the wellbore, and the potential for movement of the buoyant CO2 in the

event of a MI loss make it an important safety consideration for GS projects. Continuous pressure

monitoring allows immediate identification of corrosion-related well integrity loss. EPA agrees with

the commenter that recording annulus fluid volume may not be appropriate. However, EPA believes

that knowing annulus fluid volume as required at §146.88(e) is a necessary component of monitoring

well mechanical integrity, but believes that knowing the annulus fluid volume added is sufficient to

meet the intent of the requirement. The final GS rule requires that owners or operators use

continuous recording devices to monitor injection pressure, rate and volume; as well as the pressure

on the annulus between the tubing and the long string casing. It also modifies the requirement in the

proposed rule to continuously monitor annulus fluid volume; it now requires recording of annulus

fluid volume added. See §§146.88(e); 146.89(b); and 146.90(b). 

Fluid level can be detected using acoustic techniques (Schubert, 1998). The Texas Class I well

regulations for industrial wells currently require continuous monitoring of annulus pressure and

volume, and the majority of injection wells in Ohio conduct continuous monitoring (GWPC, 2006).

At least one commenter indicated that the technology required for continuous monitoring is currently

available and should not present an undue cost burden. Continuous annulus monitoring is also

conducted at the commercial-scaled carbon capture and geologic sequestration operation at the In

Salah, Algeria natural gas plant where more than 3 million tons of CO2 have been sequestered since

2004. The technology for continuous monitoring is available, is currently in fairly wide use, and the

costs are not burdensome, especially given the operational and safety considerations addressed.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24916

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4720 2.7.2 Operational recordkeeping and reporting 

Comment: EPA Proposal: (b) To evaluate the absence of significant leaks under paragraph 

(a)(1) of this section, owners or operators must, following an initial annulus 

pressure test, continuously monitor injection pressure, rate, injected volumes, 

and pressure on the annulus between tubing and long stem casing and annulus 

fluid volume as specified in § 146.88(e); 

GWPC Recommendations: (b) To evaluate the absence of significant leaks under 

paragraph (a)(1) of this section, owners or operators must, following an initial 

annulus pressure test, continuously monitor and record at least daily injection 

pressure, rate, injected volumes, and pressure on the annulus between tubing 

and long stem casing and annulus fluid volume as specified in §146.88 (e); 

Rationale: We believe that injection parameters must not only be monitored but 

should be recorded at least daily. We further believe the use of monitoring with 

digital equipment which records readings on an appropriate frequency should be 

considered continuous for purposes of this section. 
Response: EPA believes that continuous pressure monitoring to demonstrate internal mechanical

integrity of Class VI wells required at §146.89(b) is important, given the potential corrosive impact

of CO2 and impurities on well materials, the potential geomechanical impacts to well integrity due to

CO2 phase changes, and the temperature and pressure effects associated with injecting supercritical

CO2. EPA also believes that the technology for continuous monitoring is practicable, available, and

is currently in fairly wide use. Class VI injection wells will be equipped with dedicated computerbased continuous pressure monitoring devices (in concert with the shut-off systems required for GS

wells), which typically take readings several times per second (i.e., more frequently than daily) and

record them electronically in a computer system. 40 CFR §146.91(a)(2) requires that monthly

averages of the continuous annulus monitoring be reported on a semiannual basis. For additional

information, please see the discussion of MITs in the final rule preamble.

Commenter Name: Steven Chester Letter ID: 0264

Commenter Organization: Michigan Department of Environmental Quality

(MDEQ)

Comment ID:

22842

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: EPA (III. A. 4.) proposes "continuous monitoring" of various injection 

parameters. 

- Staff believes "continuous monitoring" is appropriate but that the 

precise definition of "continuous monitoring" may be contentious. 

Response: EPA agrees with the commenter regarding the importance of demonstrating internal

mechanical integrity (MI) and believes that continuous pressure monitoring to demonstrate internal

mechanical integrity of Class VI wells is important, given the potential corrosive impact of CO2 and

impurities on well materials, the potential geomechanical impacts to well integrity due to CO2 phase

changes, and the temperature and pressure effects associated with injecting supercritical CO2. See

§146.89(b). EPA also believes that the technology for continuous monitoring is practicable,

available, and is currently in fairly wide use. EPA anticipates that the owner or operator’s testing and

monitoring plan will describe the proposed specific equipment and recording frequency.

Commenter Name: Steven Chester Letter ID: 0264

Commenter Organization: Michigan Department of Environmental Quality

(MDEQ)

Comment ID:

22843

Other EPA Comment Codes and Descriptions: 4540 2.5.2 Proposed external MIT requirements;

4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: EPA (III . A. 5.) proposes eliminating periodic internal mechanical integrity 

tests (MIT) in favor of continuous monitoring and to require external MITs on an 

annual basis. 

- Staff believes that continuous internal monitoring of injection wells is 

appropriate. Staff believes that external MITs should be conducted once every 

five years. 

Response: EPA agrees with the commenter regarding the importance of demonstrating internal

mechanical integrity (MI), and the final GS rule retains the requirement for continuous pressure

monitoring of Class VI wells to enable the immediate identification of corrosion-related internal

mechanical integrity problems that could lead to significant well problems and failure. 
EPA disagrees that a five-year external MIT is appropriate. The final GS regulation retains the

requirement that owners or operators of Class VI wells must demonstrate injection well external

mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable for the

protection of USDWs from endangerment given the unique nature of CO2 GS relative to other

injection operations, including the potential corrosive impact of CO2 in the presence of water and

impurities on well materials, the potential geomechanical impacts to well integrity due to CO2 phase

changes, the temperature and pressure effects associated with injecting supercritical CO2, and the

buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS.

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA, 1999). Given the potential for CO2 to be corrosive (i.e., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate.

For additional information, please see the discussion of MITs in the final rule preamble.

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.

Comment Code: 4540 2.5.2 Proposed external MIT requirements 

Individual Comments

Commenter Name: Brianne Metzger Letter ID: 0151

Commenter Organization: Spectra Energy Corp Comment ID: 21842

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: EPA is also proposing that an owner/operator demonstrate "external mechanical 

integrity pursuant to § 146.89(c) at least once per year." 40 C.F.R. 146.90(e). 

External mechanical integrity is not defined. Therefore, we would ask EPA to 

clarify what is meant by this term. 

Response: EPA clarifies that mechanical integrity refers to the absence (1) of significant leak in the

casing, tubing, or packer and (2) of significant fluid movement into a USDW through channels

adjacent to the injection wellbore. The second half of this definition refers to external mechanical

integrity.

EPA adds that a properly designed and operated well should have no leakage in the casing, tubing,

or packer and no fluid movement into a USDW through channels adjacent to the wellbore. While the

intent of MITs is to detect these types of problems as early as possible, the goal of the well design

and construction requirements at §146.86 is the complete absence of such problems. For additional

information, please see the discussion of MITs in the final rule preamble.

Commenter Name: Michael Mudd Letter ID: 0167
Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 22471

Comment: Regarding external MITs, it isn’t clear whether the requirement involves 

testing while injection CO2 or another fluid (e.g., water). Also, it isn’t 

clear whether or not these methods work with CO2; therefore, new/alternate 

methods may be needed. 

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

log or temperature or noise logs) are effective methods for demonstrating external MI. They are

currently used by owners or operators of Class I and Class II wells, including owners or operators

injecting CO2. The Agency notes that the regulations do provide the Director the flexibility at

§146.89(e) to approve the use of alternative MIT methods. They have been used successfully by

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

the injection well system. For additional information, please see the discussion of MITs in the final

rule preamble.

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

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

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

requirements are appropriate or necessary.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24192

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: Rule Provision: 146.89(c) 

API Comments: (c) At least once per year, the owner or operator must confirm the 

absence of significant fluid movement under paragraph (a)(2) of this section 

USING A METHOD ACCEPTABLE TO THE DIRECTOR (E.G. INCLUDING DIAGNOSTIC

SURVEYS 

SUCH AS OXYGEN-ACTIVATION LOGGING OR TEMPERATURE OR NOISE LOGS). 

(1) A tracer survey such as oxygen-activation 

logging; 

(2) A temperature or noise log; or 

(3) A casing inspection log, if required by the 

Director.

Rationale: Revised text supports a performance-based approach and allows the 

development and use of new technologies as they become available. Cement 

circulation to the surface is not necessary because having the open annulus 

above the top of cement allows regular monitoring of annular pressure which 

could indicate leakage. 

Subsection (3) was deleted because it requires the tubing to be pulled at 

significant cost and risk of uncontrolled releases. 

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

log or temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for

decades. The Agency notes that the regulations do provide the Director the flexibility at §146.89(e)

to approve the use of alternative MIT methods. 

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind

the casing, but clarifies that it is appropriate to be used to determine the presence or absence of

corrosion of the long-string casing, and is required if the Director determines that it is necessary

based on site-specific information. EPA has revised the final GS rule to require that the frequency of

the casing inspection log must be specified in the approved testing and monitoring plan. See

§146.89(d). 

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23869

Other EPA Comment Codes and Descriptions: 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: Proposed section 146.89(d) would give the Director discretion to require any 

other test to evaluate mechanical integrity, if the alternative tests are 

approved and published in the Federal Register. We recommend that EPA revise the 

mechanical integrity testing requirements (1) to give the Director discretion to 

approve not only different testing requirements but the timing for testing 

requirements; and (2) to require such testing no more frequently than a 

reasonable multi-year period, or sooner if there is evidence that earlier 

testing is warranted. 

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

log or temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for

decades. The Agency notes that the regulations provide the Director the flexibility at §146.89(e) to

approve the use of alternative MIT methods. 

The final GS regulation retains the requirement that owners or operators of Class VI wells must

demonstrate injection well external mechanical integrity at least once annually. See §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.

A comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that Class I

wells injecting corrosive fluids fail MITs at rates two to three times higher than those that inject noncorrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (i.e., in the presence of

water or aqueous formation fluids), there is a potential risk factor for MIT failure and, for this

reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

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. For additional

information, please see the discussion of MITs in the final rule preamble.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24476

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: Rule Provision: 146.89(c) 

Proposed CCS Group Recommendations:(c) At least once per year, the owner or 

operator must confirm the absence of significant fluid movement under paragraph 

(a)(2) of this section USING A METHOD ACCEPTABLE TO THE DIRECTOR (E.G.

INCLUDING 

DIAGNOSTIC SURVEYS SUCH AS OXYGEN-ACTIVATION LOGGING OR TEMPERATURE

OR NOISE 

LOGS). (1) A tracer survey such as oxygen-activation logging; (2) A 

temperature or noise log; or (3) A casing inspection log, if required by the 

Director.

Basis for CCS Group Comments: Revised text supports a performance-based approach 

and allows the development and use of new technologies as they become available. 

Cement circulation to the surface is not necessary because having the open 

annulus above the top of cement allows regular monitoring of annular pressure 

which could indicate leakage. 

We recommend deletion of subsection (3) because it would require that the tubing 

be pulled at significant cost and risk of uncontrolled releases. 

Response: EPA believes that the MITs described in 146.89(c) of the rule (an approved tracer log or

temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for decades. The

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

of alternative MIT methods. 

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind

the casing, but clarifies that it can be used to determine the presence or absence of corrosion of the

long-string casing, and is required if the Director determines that it is necessary based on sitespecific information. EPA has revised the final GS rule to require that the frequency of the casing

inspection log must be specified in the approved testing and monitoring plan. See §146.89(d). 

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24699

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: Rule Provision: 146.89(c) 

Anadarko Petroleum Corporation (APC) Comments: (c) At least once per year, the 
owner or operator must confirm the absence of significant fluid movement under 

paragraph (a)(2) of this section USING A METHOD ACCEPTABLE TO THE DIRECTOR (E.G. 

INCLUDING DIAGNOSTIC SURVEYS SUCH AS OXYGENACTIVATION LOGGING OR

TEMPERATURE OR 

NOISE LOGS). 

(1) A tracer survey such as oxygen-activation logging; (2) A temperature or 

noise log; or (3) A casing inspection log, if required by the Director.

Rationale: Revised text supports a performance-based approach and allows the 

development and use of new technologies as they become available. Cement 

circulation to the surface is not necessary because having the open annulus 

above the top of cement allows regular monitoring of annular pressure which 

could indicate leakage. 

Number 3 was deleted because it requires the tubing to be pulled at significant 

cost and risk of uncontrolled releases. 

Response: EPA believes that the MITs described in 146.89(c) of the rule (an approved tracer log or

temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for decades. The

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

of alternative MIT methods. 

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind

the casing, but clarifies that it is appropriate for determining the presence or absence of corrosion of

the long-string casing, and is required if the Director determines that it is necessary based on sitespecific information. EPA has revised the final GS rule to require that the frequency of the casing

inspection log must be specified in the approved testing and monitoring plan. See §146.89(d). 

Commenter Name: Neeraj Gupta Letter ID: 0229

Commenter Organization: Battelle Energy Technology (BET) Comment ID: 21849

Comment: Page 98, External MIT Testing- We suggest review of the experience with 

temperature logs, radioactive tracer logs, and noise logs to determine which 

method is best for evaluating external MIT. For example, in our experience 

temperature logs do not provide much indication of corrosion. In general, we 

have found wireline cement bond logs to be the best evaluator of external 

mechanical integrity. However, most assessment of these is needed before firm 

conclusions can be made. 

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

log or temperature or noise logs) are effective methods for demonstrating external MI. They are

currently used by owners or operators of Class I and Class II wells. The Agency notes that the

regulations do provide the Director flexibility at §146.89(e) to approve the use of alternative MIT

methods. They have been used successfully by injection well operators for decades and provide an

important early warning of potential problems in the injection well system. For additional

information, please see the discussion of MITs in the final rule preamble.
EPA is using an adaptive approach to regulating GS. The Agency plans to collect and review data

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

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

requirements are appropriate or necessary.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24917

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: Rule Provision: 146.89(c) 

EPA Proposal: (c) At least once per year, the owner or operator must use one of 

the following methods to determine the absence of significant fluid movement 

under paragraph (a)(2) of this section: 

(1) A tracer survey such as oxygen-activation logging; 

(2) A temperature or noise log; or 

(3) A casing inspection log, if required by the Director. 

GWPC Recommendations: (c) At least once per year, the owner or operator must 

confirm the absence of significant fluid movement under paragraph (a)(2) of this 

section using a method acceptable to the Director (e.g. including diagnostic 

surveys such as oxygen-activation logging or temperature or noise logs). 

Delete (1) 

Delete (2) 

Delete (3) 

Rationale: Revised text supports a performance-based approach and allows the 

development and use of new technologies as they become available. 

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

log or temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for

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

approve the use of alternative MIT methods. 

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind

the casing, but clarifies that it is appropriate to be used to determine the presence or absence of

corrosion of the long-string casing, and is required if the Director determines that it is necessary

based on site-specific information. EPA has revised the final GS rule to require that the frequency of

the casing inspection log must be specified in the approved testing and monitoring plan. See

§146.89(d). 

Commenter Name: Claire Olson Letter ID: 0260

Commenter Organization: Basin Electric Power Cooperative Comment ID: 22398

Comment: "5. Proposed Mechanical Integrity Testing Requirements" 
The referenced annual tracer survey, temperature, or noise log is too burdensome 

and should be changed to a five-year frequency or other criteria. 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually as required under §146.89(c). EPA believes this

is justifiable for the protection of USDWs from endangerment given the unique nature of CO2 GS

relative to other injection operations, including the potential corrosive impact of CO2 in the presence

of water and impurities on well materials, the potential geomechanical impacts to well integrity due

to CO2 phase changes, the temperature and pressure effects associated with injecting supercritical

CO2, and the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2

GS, EPA chose a more conservative initial approach in the early stages of deployment for GS.

A comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that Class I

wells injecting corrosive fluids fail MITs at rates two to three times higher than those that inject noncorrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the presence of

water or aqueous formation fluids), there is a potential risk factor for MIT failure and, for this

reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. For

additional information, please see the discussion of MITs in the final rule preamble.

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.

Commenter Name: Steven Chester Letter ID: 0264

Commenter Organization: Michigan Department of Environmental Quality

(MDEQ)

Comment ID:

22843

Other EPA Comment Codes and Descriptions: 4520 2.5.1 Continuous internal mechanical

integrity monitoring (seeking comment); 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: EPA (III . A. 5.) proposes eliminating periodic internal mechanical integrity 

tests (MIT) in favor of continuous monitoring and to require external MITs on an 

annual basis. 

- Staff believes that continuous internal monitoring of injection wells is 

appropriate. Staff believes that external MITs should be conducted once every 

five years. 

Response: EPA agrees with the commenter regarding the importance of demonstrating internal

mechanical integrity (MI), and the final GS rule retains the requirement for continuous pressure

monitoring of Class VI wells to enable the immediate identification of corrosion-related internal

mechanical integrity problems that could lead to significant well problems and failure. 

EPA disagrees that a five-year external MIT is appropriate. The final GS regulation retains the

requirement that owners or operators of Class VI wells must demonstrate injection well external

mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable for the

protection of USDWs from endangerment given the unique nature of CO2 GS relative to other

injection operations, including the potential corrosive impact of CO2 in the presence of water and
impurities on well materials, the potential geomechanical impacts to well integrity due to CO2 phase

changes, the temperature and pressure effects associated with injecting supercritical CO2, and the

buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS.

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA, 1999). Given the potential for CO2 to be corrosive (i.e., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate.

For additional information, please see the discussion of MITs in the final rule preamble.

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.

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

Individual Comments

Commenter Name: Michael H. Cochran Letter ID:

0108

Commenter Organization: Bureau of Water, Division of Environment, Kansas

Department of Health & Environment (KDHE)

Comment

ID: 21980

Other EPA Comment Codes and Descriptions: 4630 2.6.3 Corrosion monitoring 

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

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

detecting corrosion problems and the degree of corrosion casing inspection logs 

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

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

movement behind the casing, but clarifies that it is appropriate for determining the presence or

absence of corrosion of the long-string casing, and is required if the Director determines that it is

necessary based on site-specific information. EPA has revised the final GS rule to require that the

frequency of the casing inspection log be specified in the approved testing and monitoring plan. See

§146.89(d). For additional information, please see the discussion of MITs in the final rule preamble.

Commenter Name: Michael H. Cochran Letter ID:

0108

Commenter Organization: Bureau of Water, Division of Environment, Kansas

Department of Health & Environment (KDHE)

Comment

ID: 21982

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

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

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

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

a time period and then a calculated amount of CO2 injected. Then injection is 
ceased and a series of shut-in temperature logs conducted and a composite of the 

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

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

log or temperature or noise logs) are effective methods for demonstrating external MI. They are

currently used by owners or operators of Class I and Class II wells. The Agency notes that the

regulations do provide the Director flexibility at §146.89(e) to approve the use of alternative MIT

methods. They have been used successfully by injection well operators for decades and provide an

important early warning of potential problems in the injection well system. EPA is developing

guidance on monitoring and testing to assist owners/operators and Directors in evaluating

requirements under 146.90, including proposed monitoring plans. The guidance describes available

technologies for implementing a testing and monitoring plan, including MITs. This guidance will be

available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

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

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

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

requirements are appropriate or necessary.

Commenter Name: John Hanger Letter ID: 0130

Commenter Organization: Pennsylvania Dept. of Env. Protection Comment ID: 21508

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: Proposed Mechanical Integrity Testing Requirements 

-"Section 146.89 Mechanical integrity. (a) A Class VI well has mechanical 

integrity if: 

(1) There is no significant leak in the casing, tubing or packer; and (2) 

There is no significant fluid movement into a USDW through channels adjacent to 

the injection well bore. 

(b) To evaluate the absence of significant leaks under paragraph (a)(1) of 

this section, owners or operators must...." 

There is no definition of "significant" in the document. A definition should be 

included that explains how the term will be defined, such as some measurement 

around a mean, a variance interval, etc. Too often the term is used without an 

understanding of its technical meaning. This will also help the permittee to 

understand what is expectated. 

-‘De minimus’ CO2 leakage values should be determined and defined, as well as 

the acceptable measurement methodology and verification practices. 

Response: A properly designed and operated well should have no leakage in the casing, tubing, or

packer and no fluid movement into a USDW through channels adjacent to the wellbore. While the

intent of MITs is to detect these types of problems as early as possible, the goal of the well design

and construction requirements at §146.86 is the complete absence of such problems. EPA clarifies

that the purpose of the "significant leakage" language in this narrow context is simply to avoid

triggering corrective actions for essentially de minimis situations. Determining whether a MIT result
should trigger follow-up action is necessarily a case and site-specific situation; as a result, EPA does

not believe it is appropriate to define the term "significant leakage" in the context of MITs. In

addition, EPA has not defined this term for purposes of other injection well classes and this has not

been shown to hinder permitting authorities' and owners or operators' ability to assess whether

injection wells have adequate mechanical integrity. EPA believes that this approach allows states

flexibility, will not interfere with the implementation of existing UIC programs, and maintains

protection of USDWs from endangerment. 

In keeping with its adaptive rulemaking approach, the Agency plans to collect and review data every

six years on early 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.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22562

Comment: Another method of ensuring the mechanical integrity of the well is the use of 

mechanical integrity tests, MITs. MITs, that raise the pressure in the well, 

like the standard annulus pressure test, are often used to measure the internal 

integrity. It is possible that the increase in pressure in the wellbore 

associated with some MITs could damage the interface between the casing and the 

cement possibly creating a leakage pathway. The use of these MITs on CO2 

injection wells should be studied before it is made a requirement. MITs such as 

radioactive tracer surveys, RATS, or other alternative methods with comparable 

results, may be more appropriate for measuring internal integrity. Furthermore, 

RATS and temperature logging may also be an effective technique for identifying 

external wellbore leakage pathways. 

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

log or temperature or noise logs) are effective methods 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. 

EPA disagrees that MITs would damage an injection well. Routine MITs are designed to measure the

sufficiency of the construction of an injection well and to detect subsequent well construction,

material, and operational problems within the well system before leaks occur. They are currently

used effectively within the UIC program to ensure MI in other classes of injection wells. Damage to

a well as a result of a routine, required MIT is unlikely and would be an indication of a sub-standard

well or a well with some type of construction and/or operational defect. Regarding the use of RATS,

EPA adds that these are used only in specific circumstances, such as in the immediate vicinity of the

well perforations/ injection zone. The regulations provide the Director flexibility at §146.89(e) to

approve the use of alternative MIT methods. MITs are a means of measuring the adequacy of the

construction of an injection well and a way to detect problems within the well system before leaks

occur. For additional information, please see the discussion of MITs in the final rule preamble.

Regarding the commenter's recommendation that EPA study MITs on GS wells, EPA clarifies that it

plans to collect and review data every six years on early 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.

Commenter Name: Christine Reimer Letter ID: 0142

Commenter Organization: National Ground Water Association Comment ID: 22606

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Proposed Rule: 146.89(c) 

Proposed revision: At least once per year, the owner or operator must use one 

of the following methods, as approved by the director, to determine the absence 

of significant fluid movement under paragraph (a)(2) of this section. 

Rationale: There was a question as to whether one of these tests individually 

would suffice in all circumstances. The change proposed is to allow the 

director to review the proposal. 

Response: EPA clarifies that all MITs the owner or operator proposes to use must be described in

the proposed testing and monitoring plan, which must be approved by the Director. See §146.90.

EPA believes that the MITs described in §146.89(c) of the rule (e.g., an approved tracer log or

temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for decades. The

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

of alternative MIT methods.

Commenter Name: Brianne Metzger Letter ID: 0151

Commenter Organization: Spectra Energy Corp Comment ID: 21833

Comment: F. Integrity Testing And Monitoring Requirements Are Excessive And The 

Definition of "Significant Leakage" Should Be Clarified. 

A significant component of the GS Rule is focused on mechanical integrity of 

injection wells to ensure against any "significant leakage" that would endanger 

USDWs. As part of the integrity testing requirements, EPA is proposing to 

require owner/operators to at least once per year determine the absence of 

significant fluid movement by using tracers, temperature or noise logs, or 

casing inspections, or any other tests as required by the Director. 40 CFR § 

146.89(c). While Spectra fully supports the need for integrity testing, we 

believe that some of the requirements are excessive and unreasonable and will 

not provide meaningful data. 

Response: EPA disagrees that the MIT requirements for Class VI wells are excessive, and 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. Given the unique nature of CO2 injection for GS (e.g., the potential

corrosivity 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 CO2 and the potential
for its movement up a wellbore), EPA believes it is important to protect USDWs from endangerment

by adopting MIT requirements that are tailored to CO2 injection for GS.

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind

the casing, but clarifies that it is appropriate for determining the presence or absence of corrosion of

the long-string casing, and is required if the Director determines that it is necessary based on sitespecific information. EPA has revised the final GS rule to require that the frequency of the casing

inspection log must be specified in the approved testing and monitoring plan. See §146.89(d). 

In addition, EPA is using an adaptive approach to regulating GS. The Agency plans to collect and

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

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

the requirements are appropriate or necessary.

Commenter Name: Brianne Metzger Letter ID: 0151

Commenter Organization: Spectra Energy Corp Comment ID: 21834

Other EPA Comment Codes and Descriptions: 1220 1.1.1.1 Terminology and definitions 

Comment: 1. EPA Should Define "Significant Leakage" Within The Context Of Endangerment. 

EPA has defined mechanical integrity as "no significant leakage" and "no 

significant fluid movement into a USDW through channels adjacent to the 

injection well bore." While Spectra agrees with EPA’s general approach here, 

we are concerned that the absence of a definition regarding what constitutes 

"significant" could create ambiguity that could be construed against the 

owner/operator and beyond authority granted under SDWA. Therefore, we would 

strongly recommend that the Agency define what constitutes "significant" or, 

alternatively, clarify under what conditions significant leakage might be 

construed. Toward this end, we believe that the term should be defined and 

construed within the statutorily defined concept of "endangerment" [2] under SDWA, 

i.e., significant leakage would be defined as any leakage that could 

potentially endanger a USDW. As one court has held, Congress’ established no 

specific metric for measuring endangerment and thus the Agency has the 

discretion to develop UIC requirements based on varied geology, Miami-Dade 

County v. EPA, 529 F.3d 1049 (11th Cir. 2008) (court upheld EPA’s rule 

eliminating the non-endangerment finding requirement for Class I municipal 

injection wells). The amount of leakage and what constitutes significant may 

vary depending upon the geologic formations and proximity to USDWs. 

2 Endangerment is defined as follows: Underground injection endangers drinking 

water sources if such injection may result in the presence in underground water 

which supplies or can reasonably be expected to supply any public water system 

of any contaminant, and if the presence of such contaminant may result in such 

system’s not complying with any national primary drinking water regulation or 

may otherwise adversely affect the health of persons. 42 U.S.C. § 300h(d). 

Response: A properly designed and operated well should have no leakage in the casing, tubing, or

packer and no fluid movement into a USDW through channels adjacent to the wellbore. While the

intent of MITs is to detect these types of problems as early as possible, the goal of the well design

and construction requirements at §146.86 is the complete absence of such problems. EPA clarifies
that the purpose of the "significant leakage" language in this narrow context is simply to avoid

triggering corrective actions for essentially de minimis situations. Determining whether a MIT result

should trigger follow-up action is necessarily a case- and site-specific situation; as a result, EPA

does not believe it is appropriate to define the term "significant leakage" in the context of MITs. In

addition, EPA has not defined this term for purposes of other injection well classes and this has not

been shown to hinder permitting authorities' and owners' or operators' ability to assess whether

injection wells have adequate mechanical integrity. EPA believes that this approach allows states

flexibility, will not interfere with the implementation of existing UIC programs, and maintains

protection of USDWs from endangerment. 

In keeping with its adaptive rulemaking approach, the Agency plans to collect and review data every

six years on early 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.

Commenter Name: Brianne Metzger Letter ID: 0151

Commenter Organization: Spectra Energy Corp Comment ID: 21836

Comment: Section 146.89(d) currently gives the Director discretion to require any other 

test to evaluate mechanical integrity, provided such alternative tests are 

approved and published in the Federal Register. We would recommend that EPA 

revise the mechanical integrity testing requirements in two ways: (1) to give 

the Director discretion to approve not only different testing requirements but 

the timing for testing requirements, and (2) to require such testing no less 

than every five years. 

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

log or temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for

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

approve the use of alternative MIT methods. 

The final GS regulation retains the requirement that owners or operators of Class VI wells must

demonstrate injection well external mechanical integrity at least once annually as required at

§146.89(c). EPA believes that the annual mechanical integrity testing is appropriate for Class VI

wells and 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.

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 
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.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24192

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4540 2.5.2 Proposed external MIT requirements 

Comment: Rule Provision: 146.89(c) 

API Comments: (c) At least once per year, the owner or operator must confirm the 

absence of significant fluid movement under paragraph (a)(2) of this section 

USING A METHOD ACCEPTABLE TO THE DIRECTOR (E.G. INCLUDING DIAGNOSTIC

SURVEYS 

SUCH AS OXYGEN-ACTIVATION LOGGING OR TEMPERATURE OR NOISE LOGS). 

(1) A tracer survey such as oxygen-activation 

logging; 

(2) A temperature or noise log; or 

(3) A casing inspection log, if required by the 

Director.

Rationale: Revised text supports a performance-based approach and allows the 

development and use of new technologies as they become available. Cement 

circulation to the surface is not necessary because having the open annulus 

above the top of cement allows regular monitoring of annular pressure which 

could indicate leakage. 

Subsection (3) was deleted because it requires the tubing to be pulled at 

significant cost and risk of uncontrolled releases. 

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

log or temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for

decades. The Agency notes that the regulations do provide the Director the flexibility at §146.89(e)

to approve the use of alternative MIT methods. 

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind

the casing, but clarifies that it is appropriate to be used to determine the presence or absence of

corrosion of the long-string casing, and is required if the Director determines that it is necessary

based on site-specific information. EPA has revised the final GS rule to require that the frequency of

the casing inspection log must be specified in the approved testing and monitoring plan. See

§146.89(d). 

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24246
Comment: in this case as well. The MIT should test integrity of the long string casing, 

packer, and tubing and to the extent practicable, should test the integrity of 

the cement isolating the injection zone. There are many methods for conducting 

MITs. EPA should allow operators adequate flexibility in selecting the 

appropriate methods for their specific situation. API RP90 provides good 

examples of various methods for detecting mechanical failures, managing those 

risks, and conducting MITs. 

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 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). 

In addition, EPA is using an adaptive approach to regulating GS. The Agency plans to collect and

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

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

the requirements are appropriate or necessary. For additional information, please see the discussion

of MITs in the final rule preamble.

Commenter Name: Robert J. Finley Letter ID: 0180

Commenter Organization: Illinois State Geological Survey Comment ID: 23638

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. 

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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24353

Other EPA Comment Codes and Descriptions: 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: integrity. With regard to "external" mechanical integrity, we believe that the 

test methods employed and the frequency of testing should be within the 

discretion of the permit writer, subject only to a requirement that external 

mechanical integrity be demonstrated through approved MIT techniques at least 

once every five years. 

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 clarifies that the regulations provide the Director discretion 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 that the annual mechanical integrity testing is appropriate for Class VI wells and 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. 
In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24476

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4540 2.5.2 Proposed external MIT requirements 

Comment: Rule Provision: 146.89(c) 

Proposed CCS Group Recommendations:(c) At least once per year, the owner or 

operator must confirm the absence of significant fluid movement under paragraph 

(a)(2) of this section USING A METHOD ACCEPTABLE TO THE DIRECTOR (E.G.

INCLUDING 

DIAGNOSTIC SURVEYS SUCH AS OXYGEN-ACTIVATION LOGGING OR TEMPERATURE

OR NOISE 

LOGS). (1) A tracer survey such as oxygen-activation logging; (2) A 

temperature or noise log; or (3) A casing inspection log, if required by the 

Director.

Basis for CCS Group Comments: Revised text supports a performance-based approach 

and allows the development and use of new technologies as they become available. 

Cement circulation to the surface is not necessary because having the open 

annulus above the top of cement allows regular monitoring of annular pressure 

which could indicate leakage. 

We recommend deletion of subsection (3) because it would require that the tubing 

be pulled at significant cost and risk of uncontrolled releases. 

Response: EPA believes that the MITs described in 146.89(c) of the rule (an approved tracer log or

temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for decades. The

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

of alternative MIT methods. 

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind

the casing, but clarifies that it can be used to determine the presence or absence of corrosion of the

long-string casing, and is required if the Director determines that it is necessary based on sitespecific information. EPA has revised the final GS rule to require that the frequency of the casing

inspection log must be specified in the approved testing and monitoring plan. See §146.89(d). 
Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24477

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.89(d) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Rule Provision: 146.89(e) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Rule Provision: 146.89(f) 

Proposed CCS Group Recommendations: Support the proposed language. 

Basis for CCS Group Comments: Agree with EPA’s rationale. 

Response: EPA acknowledges the comments and the final rule retains the text as proposed.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24538

Comment: in this case as well. The MIT should test integrity of the long string casing, 

packer, and tubing and to the extent practicable, should test the integrity of 

the cement isolating the injection zone. There are many methods for conducting 

MITs. EPA should allow operators adequate flexibility in selecting the 

appropriate methods for their specific situation. API RP90 provides good 

examples of various methods for detecting mechanical failures, managing those 

risks, and conducting MITs. 

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 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 at §146.90. EPA clarifies that the

regulation provides the Director discretion 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). 

In addition, EPA is using an adaptive approach to regulating GS. The Agency plans to collect and

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

information and appropriate documentation are being collected, and to determine if modifications to
the requirements are appropriate or necessary.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24699

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4540 2.5.2 Proposed external MIT requirements 

Comment: Rule Provision: 146.89(c) 

Anadarko Petroleum Corporation (APC) Comments: (c) At least once per year, the 

owner or operator must confirm the absence of significant fluid movement under 

paragraph (a)(2) of this section USING A METHOD ACCEPTABLE TO THE DIRECTOR (E.G. 

INCLUDING DIAGNOSTIC SURVEYS SUCH AS OXYGENACTIVATION LOGGING OR

TEMPERATURE OR 

NOISE LOGS). 

(1) A tracer survey such as oxygen-activation logging; (2) A temperature or 

noise log; or (3) A casing inspection log, if required by the Director.

Rationale: Revised text supports a performance-based approach and allows the 

development and use of new technologies as they become available. Cement 

circulation to the surface is not necessary because having the open annulus 

above the top of cement allows regular monitoring of annular pressure which 

could indicate leakage. 

Number 3 was deleted because it requires the tubing to be pulled at significant 

cost and risk of uncontrolled releases. 

Response: EPA believes that the MITs described in 146.89(c) of the rule (an approved tracer log or

temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for decades. The

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

of alternative MIT methods. 

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind

the casing, but clarifies that it is appropriate for determining the presence or absence of corrosion of

the long-string casing, and is required if the Director determines that it is necessary based on sitespecific information. EPA has revised the final GS rule to require that the frequency of the casing

inspection log must be specified in the approved testing and monitoring plan. See §146.89(d). 

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24968

Comment: APC recommends 5-year frequency in this case as well. The MIT should test 

integrity of the long string casing, packer, and tubing and to the extent 

practicable, should test the integrity of the cement isolating the injection 

zone. There are many methods for conducting MITs. EPA should allow operators 

adequate flexibility in selecting the appropriate methods for their specific 

situation. API RP90 provides good examples of methods for detecting mechanical 
failures, managing those risks, and conducting MITs. 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable

for the protection of USDWs from endangerment given the unique nature of CO2 GS relative to

other injection operations, including the potential corrosive impact of CO2 in the presence of water

and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2

phase changes, the temperature and pressure effects associated with injecting supercritical CO2, and

the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS.

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

EPA also 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 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 provides the

Director discretion 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). 

In addition, EPA is using an adaptive approach to regulating GS. The Agency plans to collect and

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

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

the requirements are appropriate or necessary.

Commenter Name: Ronald Evans Letter ID: 0215

Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24307

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: F. § 146.89 Mechanical integrity. 

1. EPA Proposed §146.89(c) At least once per year, the owner or operator 

must use one of the following methods to determine the absence of 

significant fluid movement under paragraph (a)(2) of this section: 

(3) A casing inspection log, if required by the Director. 

Among the test protocols prescribed by the proposed rule to confirm lack of 

significant fluid movement is a casing inspection log. Although this log is 

optional, it may be required by the Director. Conducting a casing inspection log 

will require the tubing to be pulled from a well, and that in turn substantially 

increases the possibility of a well control event (that is a loss of control 
over well operation). Accordingly, the technique should only be mandated when 

other testing methodologies are unavailable. Denbury suggests the following 

edit: 

§146.89(c) At least once per year, the owner or operator must use one of 

the following methods to determine the absence of significant fluid 

movement under paragraph (a)(2) of this section: 

(3) A casing inspection log, if A TRACER SURVEY OR A TEMPERATURE OR 

NOISE LOG CANNOT BE OBTAINED AND A CASING INSPECTION LOG IS THUS 

required by the Director. 

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

movement behind the casing, but clarifies that it is appropriate for determining the presence or

absence of corrosion of the long-string casing, and is required if the Director determines that it is

necessary based on site-specific information. EPA has revised the final GS rule to require that the

frequency of the casing inspection log be specified in the approved testing and monitoring plan at

§146.89(d).

Commenter Name: Tiffany Rau Letter ID: 0224

Commenter Organization: Hydrogen Energy International Comment ID: 21694

Comment: Section 146.89(c) lists specific methodologies to monitor fluid movement. HEI 

strongly disagrees with the requirement of any particular methodology because 

this would limit technology development and favor certain technologies to the 

exclusion of others without any rationale basis. 

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 clarifies that the regulations provides the Director discretion 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). 

In addition, EPA is using an adaptive approach to regulating GS. The Agency plans to collect and

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

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

the requirements are appropriate or necessary. EPA believes this flexibility and the adaptive

approach will allow the incorporation of future technologies.

Commenter Name: Brian Williams Letter ID: 0225

Commenter Organization: BP Alternative Energy North America, Inc. (BP) Comment ID: 21745

Comment: Section 146.89(c) lists specific methodologies to monitor fluid movement. BP 

strongly disagrees with the requirement of any particular methodology because 

this would limit technology development and favor certain technologies to the 

exclusion of others without any rationale basis. 

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 clarifies that the regulations provides the Director discretion 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). 

In addition, EPA is using an adaptive approach to regulating GS. The Agency plans to collect and

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

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

the requirements are appropriate or necessary. EPA believes this flexibility and the adaptive

approach will allow the incorporation of future technologies.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23250

Comment: 28. EPA’s proposal would require owners or operators of Class VI GS projects to 

monitor internal mechanical integrity of their injection wells by continuously 

monitoring injection pressure, flow rate, and injected volumes, as well as the 

annular pressure and fluid volume to assure that no anomalies occur that may 

indicate an internal leak. EPA requests comment on the practicability of this 

requirement. EPA Notice 43513. 

The monitoring of this data is appropriate. Continuous monitoring should be 

clarified as daily for most applications. This could be more stringent or 

frequent on a case-by-case basis. 

Response: EPA agrees with the commenter regarding the importance of demonstrating internal

mechanical integrity (MI), and that continuous pressure monitoring of Class VI wells is appropriate.

EPA disagrees with the suggested changes, however. Class VI injection wells will be equipped with

dedicated computer-based continuous pressure monitoring devices (in concert with the shut-off

systems required for GS wells), which typically take readings several times per second (e.g., more

frequently than daily) and record them electronically in a computer system. 

Continuous monitoring was found to be very important in an EPA study of UIC Class I internal MIT

failure rates and causes (USEPA 1993). The study reviewed MIT results over a 5 year period and

found 135 MIT failures in 428 wells (a single well can have more than one MIT failure). In all cases,

the MIT failures were found through continuous annulus monitoring which served the important role

of an early warning to prevent any well failure. Class VI injection wells will be equipped with

dedicated computer-based continuous pressure monitoring devices (in concert with the shut-off

systems required for GS wells), which typically take readings several times per second and record

them electronically in a computer system. §146.91(a)(2) requires that monthly averages of the

continuous annulus monitoring be reported on a semiannual basis.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24917

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language; 4540 2.5.2 Proposed external MIT requirements 

Comment: Rule Provision: 146.89(c) 
EPA Proposal: (c) At least once per year, the owner or operator must use one of 

the following methods to determine the absence of significant fluid movement 

under paragraph (a)(2) of this section: 

(1) A tracer survey such as oxygen-activation logging; 

(2) A temperature or noise log; or 

(3) A casing inspection log, if required by the Director. 

GWPC Recommendations: (c) At least once per year, the owner or operator must 

confirm the absence of significant fluid movement under paragraph (a)(2) of this 

section using a method acceptable to the Director (e.g. including diagnostic 

surveys such as oxygen-activation logging or temperature or noise logs). 

Delete (1) 

Delete (2) 

Delete (3) 

Rationale: Revised text supports a performance-based approach and allows the 

development and use of new technologies as they become available. 

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

log or temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for

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

approve the use of alternative MIT methods. 

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind

the casing, but clarifies that it is appropriate to be used to determine the presence or absence of

corrosion of the long-string casing, and is required if the Director determines that it is necessary

based on site-specific information. EPA has revised the final GS rule to require that the frequency of

the casing inspection log must be specified in the approved testing and monitoring plan. See

§146.89(d). 

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24918

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: EPA Proposal: (d) The Director may require any other test to evaluate mechanical 

integrity under paragraph (a)(1) or (a)(2) of this section. Also, the Director 

may allow the use of a test to demonstrate mechanical integrity other than those 

listed above with the written approval of the Administrator. To obtain 

approval, the Director must submit a written request to the Administrator, which 

must set forth the proposed test and all technical data supporting its use. The 

Administrator must approve the request if it will reliably demonstrate the 

mechanical integrity of wells for which its use is proposed. Any alternate 

method approved by the Administrator will be published in the Federal Register 

and may be used in all States in accordance with applicable State law unless its 

use is restricted at the time of approval by the Administrator. 
GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Response: EPA acknowledges the comment and the final rule retains the text as proposed.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24919

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Rule Provision: 146.89(e) 

EPA Proposal: (e) In conducting and evaluating the tests enumerated in this 

section or others to be allowed by the Director, the owner or operator and the 

Director must apply methods and standards generally accepted in the industry. 

When the owner or operator reports the results of mechanical integrity tests to 

the Director, he/she shall include a description of the test(s) and the 

method(s) used. In making his/her evaluation, the Director must review 

monitoring and other test data submitted since the previous evaluation. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Response: EPA acknowledges the comment and the final rule retains the text as proposed.

Commenter Name: Michel Paque Letter ID: 0259

Commenter Organization: Ground Water Protection Council Comment ID: 24920

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: EPA Proposal: (f) The Director may require additional or alternative tests if 

the results presented by the owner or operator under paragraph (d) of this 

section are not satisfactory to the Director to demonstrate that there is no 

significant leak in the casing, tubing or packer or significant movement of 

fluid into or between USDWs resulting from the injection activity as stated in 

paragraphs (a)(1) and (2) of this section. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Response: EPA acknowledges the comment and the final rule retains the text as proposed.

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment) 
Individual Comments

Commenter Name: Michael H. Cochran Letter ID:

0108

Commenter Organization: Bureau of Water, Division of Environment, Kansas

Department of Health & Environment (KDHE)

Comment

ID: 21981

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

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

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

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

requirement that owners or operators of Class VI wells must demonstrate injection well external

mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable for the

protection of USDWs from endangerment given the unique nature of CO2 GS relative to other

injection operations, including the potential corrosive impact of CO2 in the presence of water and

impurities on well materials, the potential geomechanical impacts to well integrity due to CO2 phase

changes, the temperature and pressure effects associated with injecting supercritical CO2, and the

buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS.

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

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

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

modifications to the requirements are appropriate or necessary.

Commenter Name: Doug Louis Letter ID: 0121

Commenter Organization: Kansas Corporation Commission Comment ID: 22083

Comment: In our opinion, external mechanical testing at a one-year frequency is excessive 

and not warranted. The frequency which Kansas requires in their regulations is 

once every four years. 

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

requirement that owners or operators of Class VI wells must demonstrate injection well external

mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable for the

protection of USDWs from endangerment given the unique nature of CO2 GS relative to other

injection operations, including the potential corrosive impact of CO2 in the presence of water and

impurities on well materials, the potential geomechanical impacts to well integrity due to CO2 phase

changes, the temperature and pressure effects associated with injecting supercritical CO2, and the

buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS.

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

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

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

modifications to the requirements are appropriate or necessary.

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24738

Comment: - The requirement for annual external mechanical integrity testing for Class VI 
wells, such testing is only required once every five years for a Class I 

hazardous waste well. 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable

for the protection of USDWs from endangerment given the unique nature of CO2 GS relative to

other injection operations, including the potential corrosive impact of CO2 in the presence of water

and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2

phase changes, the temperature and pressure effects associated with injecting supercritical CO2, and

the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS.

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.

Commenter Name: Leslie Savage Letter ID: 0122

Commenter Organization: Railroad Commission of Texas (RRC) Comment ID: 24751

Comment: b. allow the Director to determine the frequency of mechnical integrity tests, 

with a minimum of 5 years; 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable

for the protection of USDWs from endangerment given the unique nature of CO2 GS relative to

other injection operations, including the potential corrosive impact of CO2 in the presence of water

and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2

phase changes, the temperature and pressure effects associated with injecting supercritical CO2, and

the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS.

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.

Commenter Name: Carl Carlsson Letter ID: 0131

Commenter Organization: SUEZ Energy Generation NA, LLC Comment ID: 21536

Comment: cost when required on new wells. However, SEGNA is opposed to requiring 

Mechanical Integrity (MI) testing more frequently than the 5 year frequency 

typically required for deep wells, particularly if such testing results in well 

downtime. Unnecessary testing and associated downtime will significantly add 

to costs, and may have additional upstream impacts on generation that may 

introduce expensive storage requirements. 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation
retains the requirement that owners or operators of Class VI wells must demonstrate injection well

external mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable

for the protection of USDWs from endangerment given the unique nature of CO2 GS relative to

other injection operations, including the potential corrosive impact of CO2 in the presence of water

and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2

phase changes, the temperature and pressure effects associated with injecting supercritical CO2, and

the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS. EPA believes

that the USDW protectiveness of MITs justifies their cost. Please see the Cost Analysis, which is

available in the rulemaking docket, for additional information on the costs of MITs.

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.

Commenter Name: Dwight Lockwood, PE, QEP Letter ID: 0141

Commenter Organization: Global Energy, Inc. Comment ID: 23121

Other EPA Comment Codes and Descriptions: 4700 2.7 Proposed Recordkeeping and Reporting

Requirements (40 CFR 146.91) 

Comment: 6.We support mechanical integrity testing and monitoring, in some respects (on a 

continuous basis). Sensors and data logging is readily available. Semi-annual 

reporting, along with other reporting requirements, is also quite reasonable. 

Response: EPA agrees with the commenter regarding the importance of demonstrating internal

mechanical integrity (MI). EPA agrees with the commenter that continuous pressure monitoring of

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

appropriate because the potentially corrosive nature of CO2 injectate streams in the presence of

water enables the immediate identification of corrosion-related internal mechanical integrity

problems that could lead to significant well problems and failure. 

Continuous monitoring was found to be very important in an EPA study of UIC Class I internal MIT

failure rates and causes (USEPA 1993). The study reviewed MIT results over a 5 year period and

found 135 MIT failures in 428 wells (a single well can have more than one MIT failure). In all cases,

the MIT failures were found through continuous annulus monitoring which served the important role

of an early warning to prevent any well failure. Class VI injection wells will be equipped with

dedicated computer-based continuous pressure monitoring devices in concert with the shut-off

systems required for GS wells, which typically take readings several times per second and record

them electronically in a computer system. §146.91(a)(2) requires that monthly averages of the

continuous annulus monitoring be reported on a semiannual basis.

EPA is retaining the semi-annual reporting requirement in the final rule at §146.91(a) in order to

ensure that permitting authorities can maintain proper oversight of GS projects, particularly in the

early stages of rule implementation and deployment of GS technologies. The Agency also clarifies

that permitting authorities may choose to require more frequent reporting, at the discretion of the

Director.

Commenter Name: Christine Reimer Letter ID: 0142
Commenter Organization: National Ground Water Association Comment ID: 22563

Comment: The integrity of the well should be measured on a regular basis such that timelapse comparisons are possible to see if there are changes within the wellbore 

over time that could lead to leakage situations. 

Response: EPA agrees that periodic external mechanical integrity testing is justifiable for the

protection of USDWs from endangerment, given the unique nature of CO2 GS relative to other

injection operations, including the potential for corrosion of the injection well components (steel

casing and cement) and the buoyant nature of the injected CO2 and is finalizing regulations that

require annual external MITs at §146.89(c).

Commenter Name: Brianne Metzger Letter ID: 0151

Commenter Organization: Spectra Energy Corp Comment ID: 21835

Comment: 2. Annual Mechanical Integrity Testing And Quarterly Corrosion Monitoring Are 

Excessive. 

We do not believe there is any compelling reason to require annual integrity 

testing. 40 C.F.R. § 146.89(c). First, our experience in Canada with sour CO2 

injection wells is that integrity testing every five years is more than 

sufficient. Alberta regulations require all operators to verify every five 

years the down hole condition to confirm hydraulic isolation. Many of our 

injection wells are reused producer wells that have been in corrosive 

environments for over 15 years. Even after 15 years, these wells are in good 

condition, based on the good design and the use of proper materials, and we 

have never experienced a leak. Annual testing and quarterly corrosion testing 

could also result in significant costs from plant shutdowns and downtime with 

very little benefit, if any, from the data generated. Many companies, 

including Spectra, conduct periodic plant-wide shutdowns to thoroughly inspect 

piping and equipment for corrosion and make any necessary equipment upgrades. 

These shutdowns, which ordinarily occur once every three to five years, are 

also used to inspect our injection wells, including pulling tubing and running 

cement bond logs and well casing integrity logs to determine the thickness and 

integrity of the steel in the boreholes. From these tests we are able to 

assess the cement and casing conditions, which provide the primary "isolation" 

mechanism from the reservoir fluids. We can and often do run noise logs that 

can assess for "channeling" behind the casing. While routine testing is 

important, the most significant part of maintaining well integrity is ensuring 

material compatibility and making certain that the cement and casing materials 

used are resistant to corrosion. We use nickel steel in some of our wells, 

which is even stronger and more corrosion resistant than stainless steel. 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable

for the protection of USDWs from endangerment given the unique nature of CO2 GS relative to

other injection operations. 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. 

While EPA acknowledges the successful history of the Class II injection program, including
injection of sour (acid) gas, the Agency believes that CO2 injection for GS is substantially different

from Class II ER operations in that: 1) the purpose of CO2 injection for GS is permanent storage,

whereas for ER operations, injected CO2 is often recovered (pumped from the sub-surface)

relatively soon after injection, 2) typically there is minimal formation pressure build-up during ER

operations because withdrawals from oil recovery wells reduce reservoir pressure, which is not the

case in GS reservoirs, and 3) the volumes of CO2 anticipated for injection for GS are significantly

larger than the volumes of CO2 injected for ER operations. These conditions illustrate that frequent

internal MITs for Class VI wells are critically important in ensuring that USDWs are protected. EPA

believes that continuous pressure monitoring to demonstrate internal mechanical integrity of GS

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

important. 

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate.

Regarding concerns about disruptions of plant operations, EPA believes that, due to the expected size

of GS fields, many GS operations will have more than one injection well, and that testing of each

well can be timed to avoid complete interruption of the project. 

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.

Commenter Name: Michael Mudd Letter ID: 0167

Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 22461

Comment: Proposed Mechanical Integrity Testing Requirement 

Proposed Regulation 

p. 43513, c. 3 "require owners and operators of Class VI GS project to monitor 

internal mechanical integrity of their injection wells by continuously 

monitoring injection pressure, flow rate, and injected volumes" 

p. 43514, c. 1 -require owners and operators of CO2 wells to demonstrate 

injection well external mechanical integrity at least once annually. 

The EPA seeks comment on the appropriate frequency of internal and external MITs 

for GS injection wells. 

Comments: 

- We recommend that an external MIT be performed on a recurrence interval of 

every 5 years, as is now typically done for other classes of UIC wells. The 

external MIT should rely primarily on results obtained from geophysical wireline logging surveys, and (if warranted by wireline geophysical survey results), 

conducting direct leakage-detection tests of suspected areas of concern. If the 
external MIT indicates the potential for a compromise to the cement seal 

characteristics or well casing integrity, then additional, more quantitative 

tests (e.g. Gasda et al. 2008) and subsequent corrective actions may be 

warranted. 

- The recommended external MIT recurrence assessment of every 5 years is 

predicated on no indications of injection system compromise that would be 

observed by changes in monitored internal MIT parameters during injection (e.g., 

injection or annular zone pressure), or pressure fall-off test response 

following normal, temporary operational shut-down periods. If at any time the 

monitoring parameters or pressure data responses indicate anomalous injection 

test system behavior, then this could indicate the need for an external MIT 

evaluation to be performed, at the discretion of the Director. 

During the injection period the proposed rule states that internal MIT should be 

performed continuously by monitoring pressures (e.g., injection and annular 

zones), injection rates and volumes, etc., and external MIT should be performed 

annually. Continuous monitoring of injection rates, volumes, and pressures 

during the injection phase seems reasonable and appropriate. The semi-annual 

reporting frequency of such results also seems reasonable. 

The proposed rule also states that external MIT be performed annually during the 

injection phase. The rationale for this is to protect USDWs given the potential 

corrosive effects on injection well components (steel casing and cement) that 

are exposed to the GS stream and the buoyant nature of the injected fluid. 

To execute an annual external MIT, the injection well would be required to be 

shut down (i.e., cease CO2 injection operation) and the internal CO2 injection 

delivery tubing system to be physically removed from the injection well. At a 

minimum, this would require that all GS projects, no matter how large, to have a 

backup injection well or multiple injection wells to be available so as to not 

adversely impact or interrupt daily plant operations. 

In general, we believe that annual external MIT evaluations would be excessive 

and overly disruptive for normal plant operations. This is because quantitative 

external MIT evaluation tests would require: 

- Removal of the surface wellhead and internal CO2 injection delivery tubing 

system 

- Performing detailed wireline geophysical surveys for cement-seal and well 

casing integrity (e.g., cement-bond log), and 

- If warranted by the results of the wireline geophysical surveys, conduct¬ing 

direct leakage-detection tests with installed internal test equipment (e.g., 

downhole internal straddle-packer system) of suspected areas of concern 

The performance of the various aforementioned elements of an external MIT and 

re-installation of components of the injection well system are likely to take 

between 2 to 5 days, depending on the characteristics of the injection well 
(e.g., injection reservoir depth), complexity of the internal CO2 injection well 

system, and whether quantitative leakage detection tests are warranted. Because 

of extended time required to conduct an external MIT program, the performance of 

fixed-annual external MIT evaluations (outside the schedule of planned plant 

operation maintenance shut-downs) are believed to be excessively disruptive. 

Reference Gasda, S. E., J. M. Nordbotten, and M. A. Celia. 2008. Determining 

effective wellbore permeability from a field pressure test: a numerical analysis 

of detection limits. Environmental Geology, 54(6), 1207-1215, 

doi:10.1007/s00254-007-0903-7. 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable

for the protection of USDWs from endangerment given the unique nature of CO2 GS relative to

other injection operations, including the potential corrosive impact of CO2 in the presence of water

and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2

phase changes, the temperature and pressure effects associated with injecting supercritical CO2, and

the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS.

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate.

Regarding concerns about disruptions of plant operations, EPA believes that, due to the expected size

of GS fields, many GS operations will have more than one injection well, and that testing of each

well can be timed to avoid complete interruption of the project. 

EPA believes that the external MITs described in 146.89(c) of the rule (an approved tracer log or

temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for decades. EPA

clarifies that the regulations provides the Director discretion 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). 

EPA acknowledges the commenter’s support of continuous monitoring to demonstrate internal MI;

the final rule retains this requirement at §146.89(b). 

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.

Commenter Name: Kyle Isakower Letter ID: 0170

Commenter Organization: American Petroleum Institute Comment ID: 24245

Comment: Rule Provisions: 146,89(c), 146,90(e) 
EPA Preamble Question: 29. EPA seeks comment on the appropriate frequency of 

internal and external MITs for GS injection wells, the appropriate types of 

MITs, and how to optimize MIT methods for GS. EPA Notice 43514. 

API Response: Timing for conducting MITs, should be based on risk and 

performance factors. Industry experience with CO2 EOR Class II program requires 

MITs every 5 years. This frequency has proven protective of USDWs. Given the 

similarities between CO2 EOR wells and GS wells, API recommends 5-year frequency 

in this case as well. The MIT should test integrity of the long string casing, 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). While EPA acknowledges the

successful history of the Class II injection program, the Agency believes that CO2 injection for GS is

substantially different from Class II ER operations and believes annual MITs are 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.

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

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.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23868

Other EPA Comment Codes and Descriptions: 4630 2.6.3 Corrosion monitoring 

Comment: We do not believe there is any compelling reason to require annual integrity 

testing or quarterly corrosion monitoring. A five-year testing routine has been 

sufficient for acid gas wells in Canada. Many known injection wells are reused 

producer wells that have been in corrosive environments for over 15 years and 

remain in good condition. Annual testing and quarterly corrosion testing could 

also result in significant costs from plant shutdowns and downtime. Many 

companies already conduct periodic plant-wide shutdowns to thoroughly inspect 

piping and equipment for corrosion and make any necessary equipment upgrades. 

These shutdowns, which ordinarily occur once every three to five years, are also 

used to inspect injection wells, including pulling tubing, running cement bond 

logs, and well casing integrity logs to determine the thickness and integrity of 

the steel in the boreholes. From these tests, companies are able to assess the 

cement and casing conditions, which provide the primary "isolation" mechanism 
from the reservoir fluids. Moreover, companies can and often do run noise logs 

that can assess for "channeling" behind the casing. 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). While EPA acknowledges the

successful history of the Class II injection program, including injection of sour (acid) gas, the

Agency believes that CO2 injection for GS is substantially different from Class II ER operations and

believes annual MITs are 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.

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate.

Regarding concerns about disruptions of plant operations, EPA believes that, due to the expected size

of GS fields, many GS operations will have more than one injection well, and that testing of each

well can be timed to avoid complete interruption of the project. 

On the topic of corrosion monitoring, EPA disagrees with commenters' assertions that corrosion

monitoring is unnecessary or excessive. CO2 in the presence of water (including water with NOx,

SOx, and H2S impurities) can be corrosive to well materials and cements. Thus, although a CO2

stream may be dry, the potential for corrosion of well materials down-hole, where the injectate can

potentially mix with water in the target formation, must be considered.

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.

Commenter Name: Frederick R. Eames Letter ID: 0178

Commenter Organization: CCS Alliance Comment ID: 23869

Other EPA Comment Codes and Descriptions: 4540 2.5.2 Proposed external MIT requirements 

Comment: Proposed section 146.89(d) would give the Director discretion to require any 

other test to evaluate mechanical integrity, if the alternative tests are 

approved and published in the Federal Register. We recommend that EPA revise the 

mechanical integrity testing requirements (1) to give the Director discretion to 

approve not only different testing requirements but the timing for testing 

requirements; and (2) to require such testing no more frequently than a 

reasonable multi-year period, or sooner if there is evidence that earlier 

testing is warranted. 

Response: EPA believes that the MITs described in §146.89(c) of the rule (e.g., an approved tracer
log or temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for

decades. The Agency notes that the regulations provide the Director the flexibility at §146.89(e) to

approve the use of alternative MIT methods. 

The final GS regulation retains the requirement that owners or operators of Class VI wells must

demonstrate injection well external mechanical integrity at least once annually. See §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.

A comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that Class I

wells injecting corrosive fluids fail MITs at rates two to three times higher than those that inject noncorrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (i.e., in the presence of

water or aqueous formation fluids), there is a potential risk factor for MIT failure and, for this

reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

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. For additional

information, please see the discussion of MITs in the final rule preamble.

Commenter Name: Bradley J. Field Letter ID: 0186

Commenter Organization: New York State Dept. of Environmental Conservation

Div. of Mineral Resources

Comment ID:

25200

Other EPA Comment Codes and Descriptions: 4520 2.5.1 Continuous internal mechanical

integrity monitoring (seeking comment) 

Comment: BB. EPA seeks comment on the appropriate frequency of internal and external MITs 

for GS injection wells, the appropriate types of MITs, and how to optimize MIT 

methods for GS. 

NYSDEC-DMN Response: As stated above, NYSDEC-DMN supports continuous monitoring 

of internal mechanical integrity for GS injection wells. For external MITs, the 

frequency should be more or less annually depending upon the specific 

circumstances. The types of tests allowed should be those appropriate under the 

specific circumstances. 

Response: EPA agrees with commenter regarding the importance of demonstrating internal

mechanical integrity (MI). The final GS rule retains the requirement for continuous pressure

monitoring of Class VI wells to demonstrate internal mechanical integrity and annual external MITs.

EPA believes that the annual external mechanical integrity testing is appropriate for GS wells. EPA

retains the requirement that owners or operators of Class VI wells demonstrate injection well
external mechanical integrity at least once annually. See §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 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 clarifies that the regulations at §148.89(e) 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. For additional information, please see the discussion of MITs

in the final rule preamble.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24353

Other EPA Comment Codes and Descriptions: 4543 2.5.2.1 MIT procedures and methods for GS

(seeking comment) 

Comment: integrity. With regard to "external" mechanical integrity, we believe that the 

test methods employed and the frequency of testing should be within the 

discretion of the permit writer, subject only to a requirement that external 

mechanical integrity be demonstrated through approved MIT techniques at least 

once every five years. 

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 clarifies that the regulations provide the Director discretion 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 that the annual mechanical integrity testing is appropriate for Class VI wells and 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. 

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the
presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

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.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190

Commenter Organization: Carbon Sequestration Council Comment ID: 24537

Comment: Rule Provisions or Federal Register Cite: 146,89(c), 146,90(e) 

EPA Preamble Question: 29. EPA seeks comment on the appropriate frequency of 

internal and external MITs for GS injection wells, the appropriate types of 

MITs, and how to optimize MIT methods for GS. EPA Notice 43514. 

CSC Response: Timing for conducting MITs, should be based on risk and 

performance factors. Industry experience with CO2 EOR Class II program requires 

MITs every 5 years. This frequency has proven protective of USDWs. Given the 

similarities between CO2 EOR wells and GS wells, CSC recommends 5-year frequency 

in this case as well. The MIT should test integrity of the long string casing, 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). While EPA acknowledges the

successful history of the Class II injection program, the Agency believes that CO2 injection for GS is

substantially different from Class II ER operations in that: 1) the purpose of CO2 injection for GS is

permanent storage, whereas for ER operations injected CO2 is often recovered (pumped from the

sub-surface) relatively soon after injection, 2) typically there is minimal formation pressure build-up

during ER operations because withdrawals from oil recovery wells reduce reservoir pressure, which

is not the case in GS reservoirs, and 3) the volumes of CO2 anticipated for injection for GS are

significantly larger than the volumes of CO2 injected for ER operations. 

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

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.

Commenter Name: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24967

Comment: Rule Provisions: 146.89(c), 146.90(e) 
EPA Rule Issue: 29. EPA seeks comment on the appropriate frequency of internal 

and external MITs for GS injection wells, the appropriate types of MITs, and how 

to optimize MIT methods for GS. EPA Notice 43514. 

Anadarko Petroleum Corporation (APC) Response: Timing for conducting MITs, 

should be based on risk and performance factors. Industry experience with CO2 

EOR Class II program requires MITs every 5 years. This frequency has proven 

protective of USDWs. Given the similarities between CO2 EOR wells and GS wells, 

APC recommends 5-year frequency in this case as well. The MIT should test 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). While EPA acknowledges the

successful history of the Class II injection program, the Agency believes that CO2 injection for GS is

substantially different from Class II ER operations in that: 1) the purpose of CO2 injection for GS is

permanent storage, whereas for ER operations injected CO2 is often recovered (pumped from the

sub-surface) relatively soon after injection, 2) typically there is minimal formation pressure build-up

during ER operations because withdrawals from oil recovery wells reduce reservoir pressure, which

is not the case in GS reservoirs, and 3) the volumes of CO2 anticipated for injection for GS are

significantly larger than the volumes of CO2 injected for ER operations. These conditions illustrate

that frequent internal MITs for Class VI wells are critically important in ensuring that USDWs are

protected. EPA believes that continuous pressure monitoring to demonstrate internal mechanical

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

injection wells, is important. 

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

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.

Commenter Name: Christopher Murray Letter ID: 0207

Commenter Organization: Pacific Northwest National Laboratory Comment ID: 22438

Comment: Proposed Mechanical Integrity Testing Requirement . . . . . . . . Page 15 

External MIT should be performed every 5 years, as is now typically done for 

other classes of UIC wells, using geophysical wire-line logging surveys. 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable

for the protection of USDWs from endangerment given the unique nature of CO2 GS relative to

other injection operations, including the potential corrosive impact of CO2 in the presence of water
and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2

phase changes, the temperature and pressure effects associated with injecting supercritical CO2, and

the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS. 

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

EPA believes that the MITs described in §146.89(c) of the rule an approved tracer log or

temperature or noise logs are effective methods to demonstrate external MI, 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 for the UIC Program for decades. 

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.

Commenter Name: Christopher Murray Letter ID: 0207

Commenter Organization: Pacific Northwest National Laboratory Comment ID: 22455

Comment: PROPOSED MECHANICAL INTEGRITY TESTING REQUIREMENT 

PROPOSED REGULATION 

p. 43513, c. 3 ...require owners and operators of Class VI GS project to monitor 

internal mechanical integrity of their injection wells by continuously 

monitoring injection pressure, flow rate, and injected volumes... 

p. 43514, c. 1 ...require owners and operators of CO2 wells to demonstrate 

injection well external mechanical integrity at least once annually. The EPA 

seeks comment on the appropriate frequency of internal and external MITs for GS 

injection wells. 

DISCUSSION 

During the injection period the proposed rule states that internal MIT should be 

performed continuously by monitoring pressures (e.g., injection and annular 

zones), injection rates and volumes, etc., and external MIT should be performed 

annually. Continuous monitoring of injection rates, volumes, and pressures 

during the injection phase seems reasonable and appropriate. The semiannual 

reporting frequency of such results also seems reasonable. 

The proposed rule also states that external MIT be performed annually during the 

injection phase. The rationale for this is to protect USDWsgiven the potential 

corrosive effects on injection well components (steel casing and cement) that are 

exposed to the GS stream and the buoyant nature of the injected fluid. 
To execute an annual external MIT, the injection well would be required to be 

shut down (i.e., cease CO2 injection operation) and the internal CO2 injection 

delivery tubing system to be physically removed from the injection well. At a 

minimum, this would require that all GS projects, no matter how large, to have a 

backup injection well or multiple injection wells to be available so as to not 

adversely impact or interrupt daily plant operations. 

In general, we believe that annual external MIT evaluations would be excessive 

and overly disruptive for normal plant operations. This is because quantitative 

external MIT evaluation tests would require: 

- Removal of the surface wellhead and internal CO2 injection delivery tubing 

system 

- Performing detailed wireline geophysical surveys for cement-seal and well 

casing integrity (e.g., cement-bond log), and 

- If warranted by the results of the wireline geophysical surveys, conducting 

direct leakage-detection tests with installed internal test equipment (e.g., 

downhole internal straddle-packer system) of suspected areas of concern 

The performance of the various aforementioned elements of an external MIT and 

re-installation of components of the injection well system are likely to take 

between 2 to 5 days, depending on the characteristics of the injection well 

(e.g., injection reservoir depth), complexity of the internal CO2 injection well 

system, and whether quantitative leakage detection tests are warranted. Because 

of extended time required to conduct an external MIT program, the performance of 

fixed-annual external MIT evaluations (outside the schedule of planned plant 

operation maintenance shut-downs) are believed to be excessively disruptive. 

PNNL RECOMMENDATION 

We recommend that an external MIT be performed on a recurrence interval of every 5 

years, as is now typically done for other classes of UIC wells. The external MIT 

should rely primarily on results obtained from geophysical wire-line logging 

surveys, and (if warranted by wireline geophysical survey results), conducting 

direct leakage-detection tests of suspected areas of concern. If the external 

MIT indicates the potential for a compromise to the cement seal characteristics 

or well casing integrity, then additional, more quantitative tests (e.g. Gasda 

et al. 2008) and subsequent corrective actions may be warranted. 

The recommended external MIT recurrence assessment of every 5 years is 

predicated on no indications of injection system compromise that would be 

observed by changes in monitored internal MIT parameters during injection 

(e.g., injection or annular zone pressure), or pressure fall-off test response 

following normal, temporary operational shut-down periods. If at any time the 

monitoring parameters or pressure data responses indicate anomalous injection 

test system behavior, then this could indicate the need for an external MIT 

evaluation to be performed, at the discretion of the Director. 
REFERENCE 

Gasda, S. E., J. M. Nordbotten, and M. A. Celia. 2008. Determining effective 

wellbore permeability from a field pressure test: a numerical analysis of 

detection limits. Environmental Geology, 54(6), 1207-1215, 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable

for the protection of USDWs from endangerment given the unique nature of CO2 GS relative to

other injection operations, including the potential corrosive impact of CO2 in the presence of water

and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2

phase changes, the temperature and pressure effects associated with injecting supercritical CO2, and

the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS.

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate.

Regarding concerns about disruptions of plant operations, EPA believes that, due to the expected size

of GS fields, many GS operations will have more than one injection well, and that testing of each

well can be timed to avoid complete interruption of the project. 

EPA believes that the external MITs described in §146.89(c) of the rule (e.g., an approved tracer log

or temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for decades. EPA

clarifies that the regulations provides the Director discretion 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). 

EPA acknowledges the commenter’s support of continuous monitoring to demonstrate internal MI;

the final rule retains this requirement at §146.89(b). 

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.

Commenter Name: Diane VanDe Hei Letter ID: 0213

Commenter Organization: Association of Metropolitan Water Agencies

(AMWA)

Comment ID:

22932

Comment: - Mechanical integrity testing 

o AMWA supports EPA’s proposal for mechanical integrity testing every year. This safeguard is

necessary to protect drinking water supplies, as wells will be drilled through USDWs to reach
confined bedrock for sequestration wells. 

Response: EPA agrees that annual external mechanical integrity testing is justifiable for the

protection of USDWs from endangerment, given the unique nature of CO2 GS relative to other

injection operations, including the potential for corrosion of the injection well components (e.g., steel

casing and cement) and the buoyant nature of the injected CO2. EPA is finalizing regulations that

require annual external MITs at §146.89(c).

Commenter Name: Andrew Duguid Letter ID: 0226

Commenter Organization: Schlumberger Carbon Services Comment ID: 24061

Other EPA Comment Codes and Descriptions: 1240 1.1.1.3 Suggested changes/edits to rule

language 

Comment: Proposed Rule: (e) A demonstration of external mechanical integrity pursuant to 

§146.89(c) at least once per year throughout the duration of the geologic 

sequestration project; 

Schlumberger Suggested Revision: (e) A demonstration of external mechanical 

integrity pursuant to §146.89(c) at least once per year throughout the life of 

the well; 

Schlumberger Rationale: - 

Response: EPA is retaining the language as proposed. EPA clarifies that the monitoring and testing

plan requirements in §146.90 cover the period prior to well plugging. External MITs are not required

once a well is plugged, as this test would no longer be possible in a plugged well. If a well is

plugged prior to site closure, no further MITs are required for that well.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23251

Comment: 29. EPA seeks comment on the appropriate frequency of internal and external MITs 

for GS injection wells, the appropriate types of MITs, and how to optimize MIT 

methods for GS. EPA Notice 43514. 

A five-year frequency to conduct and review internal and external mechanical 

integrity is appropriate. A standard pressure test utilizing a fluid compatible 

with the annular fluid is widely practiced but other methods should be 

available. More frequent testing or review could be required based upon 

specific factors. 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable

for the protection of USDWs from endangerment given the unique nature of CO2 GS relative to

other injection operations, including the potential corrosive impact of CO2 in the presence of water

and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2

phase changes, the temperature and pressure effects associated with injecting supercritical CO2, and

the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS. 
In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

EPA clarifies that internal MI must be demonstrated through continuous pressure monitoring under

§146.89(b); EPA believes this is superior to an annual annulus pressure MIT, given the unique

properties of CO2 injection 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.

Commenter Name: Mark Bohrer Letter ID: 0241

Commenter Organization: North Dakota Industrial Commission Comment ID: 23300

Comment: 146.89(c) Annual tracer surveys, temperature or noise logs, or casing inspection 

logs is too burdensome. This frequency should coincide with AOR reevaluation. 

Response: 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.

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind

the casing, but clarifies that it is appropriate for determining the presence or absence of corrosion of

the long-string casing, and is required if the Director determines that it is necessary based on sitespecific information. EPA has revised the final GS rule to require that the frequency of the casing

inspection log must be specified in the approved testing and monitoring plan. See §146.89(d). 

EPA adds that it is using an adaptive approach to regulating GS. The Agency will, every six years,

collect and review data on GS projects, including MIT data, to determine whether the appropriate

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

determine if modifications to the requirements are appropriate or necessary.
Letter ID: 0263

Commenter Organization: Interstate Oil & Gas Compact Commission Comment ID: 22815

Comment: III A. 5 Proposed Mechanical Integrity Testing Requirements 

DD. EPA seeks comment on the appropriate frequency of internal and external MITs 

for GS injection wells, the appropriate types of MITs, and how to optimize 

MIT methods for GS. 

IOGCC Response: For internal MITs for GS injection wells, 5 years would be a 

sufficient frequency. For external MITs, the frequency should generally be annual 

depending upon the specific circumstances. The types softest should be those 

which are most appropriate under the specific circumstances. 

Response: EPA disagrees that a five-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable

for the protection of USDWs from endangerment given the unique nature of CO2 GS relative to

other injection operations, including the potential corrosive impact of CO2 in the presence of water

and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2

phase changes, the temperature and pressure effects associated with injecting supercritical CO2, and

the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS.. 

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

EPA believes that the MITs described in §146.89(c) of the rule (e.g., an approved tracer log or

temperature or noise logs) are effective methods to demonstrate external MI, 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 for the UIC Program for decades. EPA

adds that the GS rule affords owners or operators the flexibility to choose appropriate MITs 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. Owners or operators should develop a plan that is

appropriate to the well’s design and construction; the Director will evaluate the plan based on

construction plans submitted with the permit application.

EPA clarifies that the regulations provides the Director discretion 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). 

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.

Commenter Name: Steven Chester Letter ID: 0264
Commenter Organization: Michigan Department of Environmental Quality

(MDEQ)

Comment ID:

22843

Other EPA Comment Codes and Descriptions: 4520 2.5.1 Continuous internal mechanical

integrity monitoring (seeking comment); 4540 2.5.2 Proposed external MIT requirements 

Comment: EPA (III . A. 5.) proposes eliminating periodic internal mechanical integrity 

tests (MIT) in favor of continuous monitoring and to require external MITs on an 

annual basis. 

- Staff believes that continuous internal monitoring of injection wells is 

appropriate. Staff believes that external MITs should be conducted once every 

five years. 

Response: EPA agrees with the commenter regarding the importance of demonstrating internal

mechanical integrity (MI), and the final GS rule retains the requirement for continuous pressure

monitoring of Class VI wells to enable the immediate identification of corrosion-related internal

mechanical integrity problems that could lead to significant well problems and failure. 

EPA disagrees that a five-year external MIT is appropriate. The final GS regulation retains the

requirement that owners or operators of Class VI wells must demonstrate injection well external

mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable for the

protection of USDWs from endangerment given the unique nature of CO2 GS relative to other

injection operations, including the potential corrosive impact of CO2 in the presence of water and

impurities on well materials, the potential geomechanical impacts to well integrity due to CO2 phase

changes, the temperature and pressure effects associated with injecting supercritical CO2, and the

buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS.

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA, 1999). Given the potential for CO2 to be corrosive (i.e., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate.

For additional information, please see the discussion of MITs in the final rule preamble.

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.

Commenter Name: Cynthia Lane Letter ID: 0528

Commenter Organization: American Water Works Association (AWWA) Comment ID: 21389

Other EPA Comment Codes and Descriptions: 4500 2.5 Proposed Mechanical Integrity Testing

(MIT) Requirements (40 CFR 146.89) 

Comment: We believe that the mechanical integrity testing requirements are well developed 

in the rule and that the one year time period that is required will provide for 

the protection of USDW's. 

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

approved tracer log or temperature or noise logs) are effective methods to demonstrate external MI,
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 for the UIC

Program for decades. For additional information, please see the discussion of MITs in the final rule

preamble.

EPA also believes that annual MITs are 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.

Commenter Name: Doug Louis Letter ID: 0530

Commenter Organization: Kansas Corporation Commission Comment ID: 21346

Comment: tracing material. In our opinion, external mechanical integrity testing at a one 

year frequency is excessive and not warranted. The frequency which Kansas 

requires in the regulation is once every four years. 

Response: EPA disagrees that a four-year external MIT is appropriate. The final GS regulation

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

external mechanical integrity at least once annually under §146.89(c). EPA believes this is justifiable

for the protection of USDWs from endangerment given the unique nature of CO2 GS relative to

other injection operations, including the potential corrosive impact of CO2 in the presence of water

and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2

phase changes, the temperature and pressure effects associated with injecting supercritical CO2, and

the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA

chose a more conservative initial approach in the early stages of deployment for GS.

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that

Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those that

inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., in the

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure and,

for this reason, EPA believes that the tailored MIT requirements in the final GS rule are appropriate. 

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.