This comment letter response contains two parts:   

(1) The original submittal from the commenter.

(2) A data base printout of EPA’s response to each point raised by the commenter.

Notes about the response letters:

• The response letters were generated by a data base used to track the content of all public

comment submittals and ensure that the Agency responds to each. Each comment letter

was assigned a Letter ID that corresponds to the last four digits of the docket number of the

original comment (as posted on www.regulations.gov).

• Each response letter includes: comment text; an EPA‐assigned comment code; and an

individual response. These are described and explained below.  

• The data base contains Comment text from the letters submitted by commenters.  

Many hard copy letters were scanned into electronic format for inclusion in the data

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

character recognition issues.  However, all original submittals were reviewed in the

process of drafting responses to ensure that the comment content was understood and

appropriately addressed.

• The content of each comment letter was divided into topic areas and assigned a unique

Comment ID.  Additionally, one or more Comment Codes (i.e., unique topic area ID) was

assigned to each discrete point raised by a commenter. This information was added to

the data base. To inform final rulemaking decisions, all comments and information

received on a given topic were reviewed by technical experts in each rule area (e.g., on

construction requirements).  

• Following decisions on the final rule requirements, Individual responses were drafted

by topic area to ensure completeness and consistency of the responses with the final

rule and other responses to similar comments.  Each discrete point made by a

commenter was given a unique response.

• Upon completion of comment responses, all information was entered into the data base.

Each letter response is a compilation of each comment and its individual response,

compiled in the order of the original comment letter.  As a result of this process, there is

repetition in the response text.  The Agency believes this approach ensures completeness

and attention to each comment letter that was submitted.   

• All comments in a topic area were reviewed, evaluated, and responded to concurrently.  

Responses on each topic area are compiled and are also available in the rulemaking docket.
EPA-HQ-OW-2008-0390-0122

Document ID: EPA-HQ-OW-2008-0390-0122

Last Name: Savage

First Name: Leslie

Title: 

Organization: Railroad Commission of Texas (RRC)

City: 

State: 

Zip Code: 

Phone Number: 

Fax Number: 

Country Code: 

Email Address: 

Current Category Code: 

Comment: November 12, 2008

Water Docket, Environmental Protection Agency 1200 Pennsylvania Ave., NW

Mailcode: 2822T Washington, DC 20460

Re: Docket ID No. EPA-HQ-OW-2008-0390 Comments From the Railroad Commission of

Texas

The Railroad Commission of Texas (RRC) appreciates the opportunity to comment on

the referenced docket, related to the United States Environmental Protection

Agency’s (EPA) proposal for Federal Requirements Under the Underground Injection

Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells

(the Proposal). The RRC appreciates the extensive preparatory work performed by

EPA as well as other federal entities, including the United States Department of

Energy (DOE). We share the EPA’s belief that CO2 sequestration has the potential

to improve air quality. We further believe that the best way to promote

economical geosequestration of CO2 initially is to link captured CO2 with oil

reserves, producing increased petroleum recovery efficiencies.

Texas is a leader in enhanced oil recovery using CO2. Texas possesses an

extensive oil and gas pipeline infrastructure capable of transporting CO2 to

various sequestration sites. The first CO2 flood occurred in 1972 in West Texas.

In 2005, over 160,000 barrels of oil per day were produced with CO2 EOR in

Texas. The RRC has permitted over 11,200 CO2 injection wells, with over 5,400 of

those being currently active. The 50 active CO2 enhanced oil recovery projects

in West Texas represent about 50 percent of total CO2 flooding activity

worldwide. CO2-driven EOR has grown steadily since 1985 and now accounts for

over 15 percent of the average yearly oil production in Texas. The oil industry

has experienced a supply shortage of CO2 over the past few years. Finding new

sources of CO2 will alleviate that shortfall and result in an increase in oil

production. The current shortage is about 0.5 billion cubic feet per day, with

industry consuming the available 1.5 billion cubic feet per day. Increased

availability of anthropogenic CO2 could accelerate this production. In April of

2004, the University of Texas Bureau of Economic Geology identified at least 31

billion barrels of oil in Texas that are recoverable using CO2-driven EOR.

The RRC has primacy over Class II wells and Class III brine mining wells in

Texas. Texas has been regulating injection wells since the 1930s. With nearly a

century of institutional experience regulating activities related to the

integrity of underground geologic zones, and decades of regulating CO2 injection

for EOR, the RRC respectfully offers the following comments in two main parts:

(1) general comments and recommendations related to the key areas of concern;

and (2) comments and recommendations on specific rule provisions (attached).

GENERAL COMMENTS

The Proposal fails to promote and encourage geosequestration of CO2. EPA’s

stated goals for this proposal are to protect Underground Sources of Drinking

Page 1
EPA-HQ-OW-2008-0390-0122

Water (USDWs) while promoting carbon capture and storage. As the proposal

stands, the regulations would succeed in protecting USDWs, but would fail to

successfully promote carbon capture and storage in any significant way.

Therefore, under the current regulatory scenario, CO2 will continue to be

released to the atmosphere in greater amounts than would ever leak from a

properly sited, constructed, and operated CO2 storage facility. One reason for

the failure is that the proposal overestimates the risk of CO2 sequestration

and, as a result, creates an overestimated implied liability. Another reason is

that the Proposal taints the technology by implying that CO2 is a waste.

Finally, the proposal includes insufficient flexibility to account for the

geographic variability of potential sites across the country. In summary, the

RRC is concerned that the Proposal overestimates the risks of CO2 geologic

sequestration, and creating barriers to rapid implementation of the technology

rather than encouraging or providing incentives to mobilize large-scale

projects.

The Proposal treats CO2 as a waste. The EPA states in the preamble that it has

not classified CO2 as a waste or a commodity. However, by using the Class I

waste injection well requirements as the framework for the Class VI

requirements, the Proposal implies that the CO2 stream is a waste. This

implication increases not only the potential liability for carbon dioxide

sequestration, but also the potential liability for anthropogenic CO2 injection

for the purpose of enhanced recovery of oil and/or natural gas.

Many provisions of the Proposal address Class VI wells from a waste based

perspective. With respect to construction, area of review (AoR) and monitoring,

the Proposal begins with the regulatory framework for Class I non-hazardous

industrial waste injection well requirements and then adds numerous layers of

requirements to prevent or detect the escape of CO2 from the injection zone.

The Proposal excludes CO2 that is a hazardous waste from regulation under the

Class VI program, but has proposed requirements for Class VI injection wells

that are more stringent than those for wells used for the injection of hazardous

waste. RRC strongly disagrees that CO2 buoyancy, corrosivity, and high injection

volumes for a Class VI project justify a Class I approach.

The Proposal overestimates the risks of CO2 injection and sequestration. As

noted in the preamble, naturally occurring CO2 has been trapped in subsurface

formations for eons. Texas and numerous other states have over 35 years of

experience in injection of large amounts of CO2 into geologic formations to

enhanced oil recovery. Over 35 million tons of CO2 are injected annually in more

than 70 projects in the United States.

In most cases, with appropriate site selection, construction, monitoring, and

testing, the risks of CO2 geologic sequestration would be comparable to the

risks of current activities such as natural gas storage, EOR and deep

underground disposal of acid gas. In those instances any regulations for Class

VI wells should reflect more closely UIC Class II standards instead of the more

stringent Class I well standards.

Both the Class VI and the Class II programs have the same goals - protection of

USDWs. Yet, EPA’s proposal implies that when the purpose of the injection

switches from enhanced recovery to sequestration, the risks to USDWs are

significantly magnified. The RRC does not agree that the volume and duration of

CO2 injection and placement are sufficiently different in measurable effect on

the underground to justify the extra layers of requirements.

However, rather than beginning its CO2 geologic sequestration framework with the

Class II well program, EPA begins with the framework of Class I non-hazardous

industrial waste injection well requirements and adds then numerous layers of

overly redundant requirements to prevent or detect the escape of CO2 from the

injection zone. The implication seems to be that EPA believes that the Class II

program is not sufficiently stringent. This implication is a major concern for

Page 2
EPA-HQ-OW-2008-0390-0122

the RRC.

In addition, the heightened stringency in the proposed requirements for Class VI

injection wells suggests that geological sequestration of CO2 is as much or more

dangerous than underground injection of other substances. The Proposal includes

numerous examples of this heightened stringency: 

- The implied recommendation that a geologic sequestration project have more

than one confining zone is much more stringent than the requirements for Class I

hazardous waste injection wells.

- The requirement that the long-string casing be cemented to the surface is

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.

- 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.

- The Proposal’s default 50-year post-injection monitoring period, while

groundwater monitoring for a Class I hazardous waste injection well is required

only until the injection zone pressure is such that USDWs cannot be impacted.

In nearly every instance where EPA indicates that additional safe-guards are

necessary, it cites as the reason the chemical characteristics of the CO2 stream

to be injected and the interaction of the CO2 stream with formation waters and

strata, the buoyant nature of CO2, and the pressure increases caused by

injection of very large volumes of CO2. However, buoyancy and chemical

characteristics of CO2 have been successfully addressed in enhanced recovery

injection projects using CO2 under the Class II UIC program. Pressure increases

can be handled by selecting formations that have been depleted and have reduced

pressures. In those formations for which the pressure has not been reduced as a

result of production or other activity, the issue of the pressure increase

resulting from injection of large amounts of CO2 can be addressed by limiting

the surface injection pressure and adequate monitoring.

The Proposal does not include sufficient flexibility. Congress mandated, through

Section 1421(b)(3)(A) of the SDWA, that UIC regulations developed by EPA permit

or provide consideration of varying geologic, hydrological, or historical

conditions in different States and in different areas within a State. Thus,

Congress cautioned EPA against a ‘one-size-fits-all’ regulatory scheme, and

mandated consideration of local conditions and practices. However, the Proposal

does not allow State directors to use their expertise and knowledge to account

for these varying conditions.

EPA states in the preamble that its reason for selecting Alternative #3 is

because it ‘provides flexibility while creating a framework of minimum

requirements to ensure consistency across the nation.’ However, by selecting

Alternative #3, EPA selected as a starting point the requirements for Class I

industrial non-hazardous wells. Because of this, the flexibility is restrained

at the very outset.

Using as the reason the unknowns and the unique characteristics of CO2

geosequestration (buoyancy, corrosivity, high injection volumes, etc.), the

Proposal seems to include the entire slate of possible technologies available to

complete, operate, monitor and close a UIC well and the injection/confining

formations. In a few areas, the Proposal provides the Director with discretion

to set certain application, permit, and monitoring criteria that are appropriate

to local geologic settings. However, because EPA began with an unnecessarily

stringent Class I framework, and added numerous other nondiscretionary

requirements, the flexibility is insufficient. The result is that the Proposal

is unnecessarily prescriptive and costly.

Page 3
EPA-HQ-OW-2008-0390-0122

The proposal does not seem to consider CO2 to be sequestered during injection

for EOR. The first economic CO2 sequestration projects will be associated with

oil and gas operations, yet the Proposal states that sequestration (and thus,

Class VI injection) begins only after enhanced recovery of oil or gas has

stopped. The implication is that the CO2 injected for enhanced recovery is not

ultimately sequestered upon cessation of injection and production activity. The

proposal grandfathers the construction of wells permitted as Class V and Class

II, but requires that the wells comply with all other requirements of Class VI

wells before injecting CO2 for sequestration.

Delegation of Primacy Congress mandated, through Section 1421(b)(3)(B)(i) of the

Safe Drinking Water Act (SDWA), that, to the extent feasible, EPA avoid

promulgating requirements that would unnecessarily disrupt State UIC programs

already in effect and being enforced in a substantial number of States.

The EPA has indicated that it will delegate the program under Section 1422 of

the SDWA. The RRC agrees with EPA that it is in the best interest of protecting

groundwater resources for the geologic sequestration of CO2 to be regulated at

the state level. However, any requirement by EPA that states accept primacy for

Class I, III and V wells as a condition for obtaining primacy for Class VI wells

will create an unreasonable burden upon states. This matter needs to be

clarified in the rule. In addition, any requirement by EPA that states with

primacy for Class I, III, and V wells also accept primacy for Class VI wells

will unnecessarily disrupt the states’ existing UIC programs and will compromise

the states’ ability to decide how best to administer the state’s program. In

addition, EPA should allow for split delegation in the Class VI program, as it

has in Texas for the Class III program, to allow the state to best determine how

to implement the Class VI program. Furthermore, EPA should not be allowed to

reopen any state’s primacy over other well classes in order for a state to

obtain primacy for the Class VI well program.

RECOMMENDATIONS

1. EPA should consider creating a subclass within the Class II well

classification for operators who wish to sequester CO2 in association with

enhanced recovery of oil or natural gas (with appropriate and necessary

additional requirements to address any CO2 issues) and allow the Class VI

injection well program to govern those injection wells used to sequester CO2 in

formations that are non-productive.

2. EPA should begin with a reasonable framework (Class II injection wells);

assure that the rules are flexible enough to consider site-specific

characteristics and knowledge gained from CO2 history and the ongoing

demonstration and pilot projects; and that include performance-based

requirements. Because of Texas’ and other States’ long experience with injection

operations, the States are in an excellent position to perceive and act upon

similarities in fluids injected, construction depth, design, operating

techniques and purposes between its Class II and potential Class VI wells.

3. EPA should provide more flexibility in the siting requirements: a.

acknowledge that some sites offer very good protection when compared to others

and ease regulatory burden on those sites; b. promote transfer of EOR to

storage; c. delete the requirement that the confining zone be free of all

transmissive faults or fractures; d. delete references to multiple confining

zones; and e. revise the Proposal to allow for site-specific characteristics and

performance- based determinations.

4. EPA should provide more flexibiilty in construction, for example, delete the

requirement that the long string casing be cemented to the surface.

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

operator to demonstrate that CO2 is sequestered, and instead of a 10-year

Page 4
EPA-HQ-OW-2008-0390-0122

default period for reevaluation of the area of review, allow the timing for such

reevaluation to be determined based on site-specific characteristics and sitespecific monitoring of the CO2 plume and pressure front.

6. EPA should provide more flexibility in the requirements for monitoring,

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;

b. allow the Director to determine the frequency of mechnical integrity tests,

with a minimum of 5 years;

c. delete references to air and soil gas monitoring, since such monitoring is a

case of too little too late - and can result in false positives due to ambient

variability; and

d. delete references to tracers, because of the numerous problems discussed in

the preamble.

7. EPA should provide for performance-based requirements for Closure and Post

Closure Care. For example, the appropriate length of time for post-injection

site care should be determined by specific conditions and characteristics of the

site, and monitoring of the pressure to determine the point at which the

injection zone pressure is such that USDWs cannot be impacted.

The RRC appreciates the opportunity and is available to answer questions at any

time. If you have any questions, please contact staff members David Cooney at

david.cooney@rrc.state.tx.us or (512)463-6977, or Leslie Savage at

leslie.savage@rrc.state.tx or (512)463-7308.

SPECIFIC RULE PROVISIONS

[SEE EPA-HQ-OW-2008-0390-0122.PDF FOR A FORMATTED VERSION OF THE COMMENTS BELOW.]

[Note: Additions to rule language are shown in upper case text. Stricken text is

shown in << >>. RRC comments are shown in { }.]

Proposed Subpart A - General Provisions

§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." }

Proposed Subpart D - Authorization by Permit

§144.36 Duration of permits.

{We agree with the proposal to issue permits for UIC wells associated with

sequestration of CO2 "for the period up to the operating life of the facility."

The substantial financial investment in a project makes a permit for the

operating like of the facility imperitive. }

Part 146 UIC Program Criteria and Standards

Page 5
EPA-HQ-OW-2008-0390-0122

§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."}

Subpart H--Criteria and Standards Applicable to Class VI Wells

§146.81 Applicability.

(a) This subpart establishes criteria and standards for UIC programs to regulate

Class VI CO2 GS injection wells. (b) This subpart applies to wells used to

inject CO2 specifically for the purpose of GS, i.e., the long-term containment

of a gaseous, liquid or supercritical CO2 stream in subsurface geologic

formations. (c) This subpart applies to owners and operators of permit or ruleauthorized Class I industrial, Class II, or Class V experimental CO2 injection

projects who seek to apply for a Class VI geologic sequestration permit for

their well or wells. If the Director determines that USDWs will not be

endangered, such wells are exempt, at the Director's discretion, from the casing

and cementing requirements at §§146.86(b) and 146.87(a)(1) through (3).

{RRC agrees that the Director evaluating a permit application to use existing

injection wells for geologic sequestration should have the discretion to exempt

wells from Class I industrial, Class II or Class V wells from the proposed

casing and cementing requirements of Class VI wells. }

(d) Definitions. The following definitions apply to this subpart. To the extent

that these definitions conflict with those in §146.3 these definitions govern:

 Area of review means the region surrounding the GS project that may be

 impacted by the injection activity. The AOR is based on computational

 modeling that accounts for the physical and chemical properties of all

 phases of the injected CO2 stream.

 Carbon dioxide plume means the underground extent, in 3-D, of an injected

 CO2 stream.

 Carbon dioxide stream means CO2 that has been captured from an emission

 source (e.g., a power plant), plus incidental associated substances derived

 from the source materials and the capture process, and any substances added

 to the stream to enable or improve the injection process. This subpart does

 not apply to any CO2 stream that meets the definition of a hazardous waste

 under 40 CFR part 261.

 Confining zone means a geologic formation, group of formations, or part of a

 formation stratigraphically overlying the injection zone that acts as a

 barrier to fluid movement.

 Corrective action means the use of Director approved methods to assure that

 wells within the AOR do not serve as conduits for the movement of fluids

 into USDWs.

 Geologic sequestration means the long-term containment of a gaseous, liquid

 or supercritical carbon dioxide stream in subsurface geologic formations.

 This term does not apply to its capture or transport.

 Geologic sequestration project means an injection well or wells used to

 emplace a CO2 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 3-D extent of

 the carbon dioxide plume, associated pressure front, and displaced brine, as

 well as the surface area above that delineated region.

Page 6
EPA-HQ-OW-2008-0390-0122

{RRC suggests adding to the end of the first sentence of the definition of

Geologic sequestration project, "or another formation, if the Director

determines that injection into the other formation will not endanger USDWs." }

 Injection zone means a geologic formation, group of formations, or part of a

 formation that is of sufficient areal extent, thickness, porosity, and

 permeability to receive CO2 through a well or wells associated with a GS

 project.

 Post-injection site care means appropriate monitoring and other actions

 (including corrective action) needed following cessation of injection to

 assure that USDWs are not endangered as required under §146.93.

 Pressure front means the zone of elevated pressure that is created by the

 injection of carbon dioxide into the subsurface. For the purposes of this

 subpart, the pressure front of a carbon dioxide plume refers to a zone where

 there is a pressure differential sufficient to cause the movement of

 injected fluids or formation fluids into a USDW.

{Why does this definition need to be different?}

 Site closure the point/time, as determined by the Director following the

 requirements under §146.93, at which the owner or operator of a GS site is

 released from post-injection site care responsibilities.

 Transmissive fault or fracture means a fault or fracture that has sufficient

 permeability and vertical extent to allow fluids to move between formations.

{Recommend that the fault or fracture be "known."}

§146.82 Required Class VI permit information.

This section sets forth the information which the owner or operator must submit

to the Director in order to be permitted as a Class VI well. The application for

a permit for construction and operation of a Class VI well must include the

following:

(a) Information required in 40 CFR 144.31(e)(1) - (6);

(b) A map showing the injection well(s) for which a permit is sought and the

applicable AOR. Within the AOR, the map must show the number, or name and

location of all injection wells, producing wells, abandoned wells, plugged wells

or dry holes, deep stratigraphic boreholes, State or EPA approved subsurface

cleanup sites, surface bodies of water, springs, mines (surface and subsurface),

quarries, water wells and other pertinent surface features including structures

intended for human occupancy and roads. The map should also show faults, if

known or suspected. Only information of public record is required to be

included on this map;

(c) The AOR based on modeling, using data obtained during logging and testing of

the well and the formation as required by paragraphs (l), (r), and (s) of this

section;

(d) Information on the geologic structure and hydrogeologic properties of the

proposed storage site and overlying formations, including:

(1) Maps and cross sections of the area of review;

(2) Location, orientation, and properties of known or suspected faults and

fractures that may transect the confining zone<<(s)>> in the area of review and

a determination that they would not interfere with containment;

(3) Information on seismic history including the presence and depth of seismic

sources and a determination that the seismicity would not interfere with

containment;

Page 7
EPA-HQ-OW-2008-0390-0122

(4) Data on the depth, areal extent, thickness, mineralogy, porosity,

permeability and capillary pressure of the injection and confining zone<<(s)>>;

including geology/facies changes based on field data which may include geologic

cores, outcrop data, seismic surveys, well logs, and names and lithologic

descriptions;

(5) Geomechanical information on fractures, stress, ductility, rock strength,

and in situ fluid pressures within the confining zone; and

(6) Geologic and topographic maps and cross sections illustrating regional

geology, hydrogeology, and the geologic structure of the local area.

(e) A tabulation of all wells within the AOR which penetrate the injection or

confining zone<<(s)>>. Such data must include a description of each well's type,

construction, date drilled, location, depth, record of plugging and/or

completion, and any additional information the Director may require;

{Definition of confining zone includes multiple formations. Do not

imply that multiple confining zones are preferable to one (good)

confining zone.}

(f) Maps and stratigraphic cross sections indicating the general vertical and

lateral limits of all USDWs, water wells and springs within the area of review,

their positions relative to the injection zone<<(s)>> and the direction of water

movement, where known;

{Consistency with definition and use of term in other areas of the rules.}

(g) Baseline geochemical data on subsurface formations, including all USDWs in

the AOR;

(h) Proposed operating data:

(1) Average and maximum daily rate and volume of the CO2 stream;

(2) Average and maximum injection pressure;

(3) The source of the CO2 stream; and

(4) An analysis of the chemical and physical characteristics of the CO2 stream;

(i) The compatibility of the CO2 stream with fluids in the injection zone and

minerals in both the injection and the confining zone<<(s)>>, based on the

results of the formation testing program, and with the materials used to

construct the well;

{See comment above.}

(j) Proposed formation testing program to obtain an analysis of the chemical and

physical characteristics of the injection zone and confining zone;

(k) Proposed stimulation program and a determination that stimulation will not

interfere with containment;

(l) The results of the formation testing program as required in paragraph (j) of

this section;

(m) Proposed procedure to outline steps necessary to conduct injection

operation;

{"Proposed procedure to outline steps" does not make sense. Recommend "Outline

of steps ...."}

(n) Schematic or other appropriate drawings of the surface and subsurface

construction details of the well;

(o) Injection well construction procedures that meet the requirements of

§146.86;

(p) Proposed AOR and corrective action plan that meets the requirements under

§146.84;

(q) The status of corrective action on wells in the AOR;

(r) All available logging and testing program data on the well required by

Page 8
EPA-HQ-OW-2008-0390-0122

§146.87;

(s) A demonstration of mechanical integrity pursuant to §146.89;

(t) A demonstration, satisfactory to the Director, that the applicant has met

the financial responsibility requirements under §146.85;

(u) Proposed testing and monitoring plan required by §146.90;

(v) Proposed injection well plugging plan required by §146.92(b);

(w) Proposed post-injection site care and site closure plan required by

§146.93(a);

(x) Proposed emergency and remedial response plan required by §146.94; and

(y) Any other information requested by the Director.

§146.83 Minimum criteria for siting.

(a) Owners and operators of Class VI wells must demonstrate to the satisfaction

of the Director that the wells will be sited in areas with a suitable geologic

system. The geologic system must be comprised of:

(1) An injection zone of sufficient areal extent, thickness, porosity, and

permeability to receive the total anticipated volume of the carbon dioxide

stream;

{Redundant - simply repeats the definition of "injection zone." Either take

this language out of the definition or take it out of here.}

(2) A confining zone<<(s)>> that is free of transmissive faults or fractures and

of sufficient areal extent and integrity to contain the injected carbon dioxide

stream and displaced formation fluids and allow injection at proposed maximum

pressures and volumes without initiating or propagating fractures in the

confining zone<<(s)>>; and

{Redundant. Repeats definition of "confining zone." Also, implies that the

confining zone cannot have a single fracture, no matter how small. Much more

stringent than for Class I hazardous wells.}

 <<(b) At the Director's discretion, owners or operators of Class VI wells must

 identify and characterize additional zones that will impede vertical fluid

 movement, are free of faults and fractures that may interfere with containment,

 allow for pressure dissipation, and provide additional opportunities for

 monitoring, mitigation and remediation.>>

{Redundant and unnecessary. Language in definition of "confining zone."}

§146.84 Area of review and corrective action.

(a) The area of review is the region surrounding the geologic sequestration

project that may be impacted by the injection activity. The area of review is

based on computational modeling that accounts for the physical and chemical

properties of all phases of the injected carbon dioxide stream.

{Redundant - same as the definition of "area of review."}

(b) The owner or operator of a Class VI well must prepare, maintain, and comply

with a plan to delineate the AOR for a proposed geologic sequestration project,

<<periodically>> reevaluate the delineation, and perform corrective action that

meets the requirements of this section AT A FREQUENCY AND IN A MANNER THAT

<<and>> is acceptable to the Director. As a part of the permit application<<

for approval by the Director>>, the owner or operator must submit an area of

review and corrective action plan that includes the following information:

(1) The method for delineating the area of review that meets the requirements of

paragraph (c) of this section, including the model to be used, assumptions that

will be made, and the site characterization data on which the model will be

based;

Page 9
EPA-HQ-OW-2008-0390-0122

(2) A description of: (i) <<The minimum fixed frequency, not to exceed 10 years,

the owner or operator proposes to reevaluate the area of review; (ii) >>The

monitoring and operational conditions that would warrant a reevaluation of the

area of review <<prior to the next scheduled reevaluation as determined by the

minimum fixed frequency established in paragraph (b)(2)(i) of this section.>>

{Suggest that there be no minimum fixed frequency for reevaluation of the AoR,

but that such review be based on site-specific circumstances. }

(II)<<(iii)>> How monitoring and operational data (e.g., injection rate and

pressure) will be used to inform an area of review reevaluation; and

(iv) How corrective action will be conducted to meet the requirements of

paragraph (d) of this section, including what corrective action will be

performed prior to injection and what, if any, portions of the area of review

will have corrective action addressed on a phased basis and how the phasing will

be determined; how corrective action will be adjusted if there are changes in

the area of review; and how THE site WILL BE accessed <<will be guaranteed >>for

future corrective action.

{Word Choice. Secure rather than guarantee. }

(c) Owners or operators of Class VI wells must perform the following actions to

delineate the area of review, identify all wells that require corrective action,

and perform corrective action on those wells:

(1) Predict, using computational modeling, the projected lateral and vertical

migration of the carbon dioxide plume and formation fluids in the subsurface

from the commencement of injection activities until the plume movement ceases,

pressure differentials sufficient to cause the movement of injected fluids or

formation fluids into a USDW are no longer present, or FOR <<after>> a fixed

time period as determined by the Director. The modelINGmust:

(i) Be based on detailed geologic data collected to characterize the injection

zone AND<<,>> confining zone<< and any additional zones>>; and anticipated

operating data, including injection pressures, rates and total volumes over the

proposed life of the geologic sequestration project;

(ii) Take into account RELEVANT <<any>> geologic heterogeneities AND<<,>> data

quality, and their possible impact on model predictions; and

(iii) Consider potential migration through KNOWN faults, fractures, and

artificial penetrations.

(2) Using methods approved by the Director, identify all KNOWN ARTIFICIAL

penetrations THROUGH THE CONFINING ZONE, including active and abandoned wells

and underground mines, in the area of review<< that may penetrate the confining

zone>>. Provide a description of each well's type, construction, date drilled,

location, depth, record of plugging and/or completion, and any additional

information the Director may require; and

(3) Determine which abandoned wells in the AOR have been plugged in a manner

that prevents the movement of CO2 or FORMATION <<associated>> fluids that may

endanger USDWs.

(d) Owners or operators of Class VI wells must perform corrective action USING

CORROSION RESISTANT MATERIAL, WHEN APPROPRIATE, on all wells IDENTIFIED IN

§146.84(C)(2) <<in the AOR that are determined to need corrective action using

methods necessary to prevent the movement of fluid into or between USDWs

including use of corrosion resistant materials, where appropriate.>>

(e) If monitoring data indicate an endangerment to USDWs, the owner or operator

must notify the Director and cease operations as required by §146.94.

Page 10
EPA-HQ-OW-2008-0390-0122

(f) <<At the minimum fixed frequency, not to exceed 10 years, as>> AS specified

in the AOR and corrective action plan, or when monitoring and operational

conditions warrant, the owner or operator must:

(1) Reevaluate the AOR in the same manner specified in paragraph (c)(1) of this

section;

(2) Identify all wells in the reevaluated AOR that require corrective action in

the same manner specified in paragraph (c)(2) of this section;

(3) Perform corrective action on wells requiring corrective action in the

reevaluated AOR in the same manner specified in paragraph (c)(3) of this

section; and

(4) Submit an amended AOR and corrective action plan or demonstrate to the

Director through monitoring data and modeling results that no CHANGE <<amendment

>>to the AOR and corrective action plan is needed.

{Appropriate frequency of determining AoR might not be "fixed." Owner or

operator might need to reevaluate AoR frequently at first, particularly with

deep brine formations about which there is little history, and then at expanding

intervals as more information is known.}

(g) The emergency and remedial response plan (as required by §146.94) and a

demonstration of financial responsibility (as described by §146.85) must account

for the entire AOR, regardless of whether or not corrective action in the area

of review is phased.

§146.85 Financial responsibility. (a) The owner or operator must demonstrate

and maintain financial responsibility and resources for corrective action (that

meets the requirements of §146.84), injection well plugging (that meets the

requirements of §146.92), post-injection site care and site closure (that meets

the requirements of §146.93), and emergency and remedial response (that meets

the requirements of §146.94) in a manner prescribed by the Director until:

(1) The Director receives and approves the completed post-injection site care

and site closure plan; and

(2) The Director determines that the site has reached the end of the postinjection site care period.

(b) The owner or operator must provide to the Director, at a frequency

determined by the Director, written updates of adjustments to the cost estimate

to account for any amendments to the AOR and corrective action plan (§146.84),

the injection well plugging plan (§146.92), and the post-injection site care and

site closure plan (§146.93).

(c) The owner or operator must notify the Director of adverse financial

conditions such as bankruptcy, that may affect the ability to carry out

injection well plugging and post-injection site care and site closure.

(d) The operator must provide an adjustment of the cost estimate to the Director

if the Director has reason to believe that the original demonstration is no

longer adequate to cover the cost of injection well plugging (as required by

§146.92) and post-injection site care and site closure (as required by §146.93).

§146.86 Injection well construction requirements. (a) General. The owner or

operator must ensure that all Class VI wells are constructed and completed to:

(1) Prevent the ENDANGERMENT OF USDWs <<movement of fluids into or between USDWs

or into any unauthorized zones>>;

(2) Permit the use of appropriate testing devices and workover tools; and

(3) Permit continuous monitoring of the annulus space between the injection

tubing and long string casing.

(b) Casing and Cementing of Class VI Wells.

Page 11
EPA-HQ-OW-2008-0390-0122

(1) Casing and cement or other materials used in the construction of each Class

VI well must have sufficient structural strength and be designed for the

OPERATING life of the WELL<<geologic sequestration project>>. All well

materials must be compatible with fluids with which the materials may be

expected to come into contact and meet or exceed standards developed for such

materials by the API, ASTM International, or comparable standards acceptable to

the Director. <<The casing and cementing program must be designed to prevent

the movement of fluids into or between USDWs.>> In order to allow the Director

to determine and specify casing and cementing requirements, the owner or

operator must provide the following information:

{The threat to the integrity of the casing and cement and other materials is

greatest during injection, and quickly decreases as the pressure dissipates

after cessation of injection. }

(i) Depth to the injection zone;

(ii) Injection pressure, external pressure, internal pressure and axial loading;

(iii) Hole size;

(iv) Size and grade of all casing strings (E.G., wall thickness, external

diameter, nominal weight, length, joint specification and construction

material);

(v) Corrosiveness of the carbon dioxide stream, and formation fluids;

(vi) Down-hole temperatures AND PRESSURES;

(vii) Lithology of injection and confining zones;

(viii) Type or grade of cement, INCLUDING ADDITIVES; and

(ix) Quantity, chemical composition, and temperature of the CO2 stream.

{Redundant - look at application requirements.}

(2) Surface casing must extend through the base of the lowermost USDW ABOVE THE

INJECTION ZONE and be cemented to the surface.

(3) At least one long string casing, using a sufficient number of centralizers,

must extend to the injection zone and must be cemented by circulating cement to

the surface in one or more stages.

{Circulation of cement unnecessary and more stringent that requirement for Class

I hazardous waste wells. RRC suggests that it may not be technically feasible

to cement the full column of one long string casing because the formations you

likely want to inject into are low-pressure, and typically won't hold a full

column of cement, making circulation impossible. RRC suggests a certain footage

of cement, such as 600 ft, and require a bond log to verify it. }

(4) Circulation of cement may be accomplished by staging. The Director may

approve an alternative method of cementing in cases where the cement cannot be

recirculated to the surface, provided the owner or operator can demonstrate by

using logs that the cement does not allow fluid movement behind the well bore.

(5) Cement and cement additives must be compatible with the CO2 stream and

formation fluids and of sufficient quality and quantity to maintain integrity

over the design life of the WELL <<geologic sequestration project>>. The

integrity and location of the cement shall be verified using technology capable

of evaluating cement quality radially and identifying the location of channels

to ensure that USDWs are not endangered.

{See comment above.}

(c) Tubing and packer.

(1) All owners or operators of Class VI wells must inject fluids through tubing

with a packer set at a depth opposite a cemented interval at the location

approved by the Director.

(2) In order for the Director to determine and specify requirements for tubing

Page 12
EPA-HQ-OW-2008-0390-0122

and packer, the owners or operators must submit the following information:

(i) Depth of setting;

(ii) Characteristics of the CO2 stream (chemical content, corrosiveness,

temperature, and density);

(iii) Injection pressure;

(iv) Annular pressure;

(v) Injection rate (intermittent or continuous) and volume of the CO2 stream;

(vi) Size of casing; and

(vii) Tubing tensile, burst, and collapse strengths.

{Repetitive - See application requirements}

§146.87 Logging, sampling, and testing prior to injection well operation.

(a) During the drilling and construction of a Class VI injection well, the owner

or operator must run appropriate logs, surveys and tests to determine or verify

the depth, thickness, porosity, permeability, and lithology of, and the salinity

of any formation fluids in, all relevant geologic formations to assure

conformance with the injection well construction requirements under §146.86, and

to establish accurate baseline data against which future measurements may be

compared. The owner or operator must submit to the Director a descriptive

report prepared by a knowledgeable log analyst that includes an interpretation

of the results of such logs and tests. At a minimum, such logs and tests must

include:

(1) Deviation checks during drilling on all holes constructed by drilling a

pilot hole which are enlarged by reaming or another method. Such checks must be

at sufficiently frequent intervals to determine the location of the borehole and

to assure that vertical avenues for fluid movement in the form of diverging

holes are not created during drilling; and

(2) Before and upon installation of the surface casing: (i) Resistivity,

spontaneous potential, and caliper logs before the casing is installed; and (ii)

A cement bond and variable density log, and a temperature log after the casing

is set and cemented.

(3) Before and upon installation of the long string casing:

(i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture

finder logs, and any other logs the Director requires for the given geology

before the casing is installed; and

(ii) A cement bond and variable density log, and a temperature log after the

casing is set and cemented.

(4) A series of tests designed to demonstrate the internal and external

mechanical integrity of injection wells, which may include:

(i) A pressure test with liquid or gas;

(ii) A tracer survey such as oxygen-activation logging;

(iii) A temperature or noise log;

(iv) A casing inspection log, if required by the Director; and

(5) Any alternative methods that provide equivalent or better information and

that are required of and/or approved of by the Director.

(b) The owner or operator must take and submit to the Director whole cores or

sidewall cores of the injection zone and confining zone system and

formation fluid samples from the injection zone(s). The Director may

accept cores from nearby wells if the owner or operator can demonstrate

that core retrieval is not possible and that such cores are

representative of conditions at the well. The Director may require the

owner or operator to core other formations in the borehole. Rule

language should be consistent with definitions.

Page 13
EPA-HQ-OW-2008-0390-0122

(c) The owner or operator must record the fluid temperature, pH, conductivity,

reservoir pressure and the static fluid level of the injection zone<<(s).>>

(d) At a minimum, the owner or operator must determine or calculate the

following information concerning the injection and confining zone<<(s)>>:

(1) Fracture pressure;

(2) Other physical and chemical characteristics of the injection and confining

zones; and (3) Physical and chemical characteristics of the formation fluids in

the injection zone.

(e) Upon completion, but prior to operation, the owner or operator must conduct

the following tests to verify hydrogeologic characteristics of the injection

zone:

(1) A pump test; or (2) Injectivity tests.

(f) The owner or operator must provide the Director with the opportunity to

witness all logging and testing by this subpart. The owner or operator must

submit a schedule of such activities to the Director 30 days prior to conducting

the first test and submit any changes to the schedule 30 days prior to the next

scheduled test.

§146.88 Injection well operating requirements.

(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.

(b) Injection between the outermost casing protecting USDWs and the well bore is

prohibited.

(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.

(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.

(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.}

(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

Page 14
EPA-HQ-OW-2008-0390-0122

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:

(1) Immediately cease injection;

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

a release of the injected carbon dioxide 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.

§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, 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.}

(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.

(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.

(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.

(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.

Page 15
EPA-HQ-OW-2008-0390-0122

§146.90 Testing and monitoring requirements. The owner or operator of a Class

VI well must prepare, maintain, and comply with a testing and monitoring plan to

verify that the geologic sequestration project is operating as permitted and is

not endangering USDWs. The testing and monitoring plan must be submitted with

the permit application, for Director approval, and must include a description of

how the owner or operator will meet the requirements of this section. Testing

and monitoring associated with geologic sequestration projects must, at a

minimum, include:

(a) Analysis of the carbon dioxide stream with sufficient frequency to yield

data representative of its chemical and physical characteristics;

(b) Installation and use, except during well workovers as defined in §146.86(d),

of 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;

(c) Corrosion monitoring of the well materials for loss of mass, thickness,

cracking, pitting and other signs of corrosion must be performed on a quarterly

basis to ensure that the well components meet the minimum standards for material

strength and performance set forth in §146.86(b) by:

(1) Placing coupons of the well construction materials in contact with the

carbon dioxide stream; or

(2) Routing the carbon dioxide stream through a loop constructed with the

material used in the well; or

(3) Using an alternative method approved by the Director;

(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:

(1) The location and number of monitoring wells must be based on specific

information about the geologic sequestration project, including injection rate

and volume, geology, the presence of artificial penetrations and other factors;

(2) The monitoring frequency and spatial distribution of monitoring wells must

be based on baseline geochemical data that has been collected under §146.82(a)

(6) and any modeling results in the AOR evaluation required by §146.84(b);

(e) A demonstration of external mechanical integrity pursuant to §146.89(c) at

least once per year throughout the duration of INJECTION <<the geologic

sequestration project;>>

{Demonstration of external mechanical integrity should not be necessary after

cessation of injection and (relatively immediate) dissipation of pressure near

the wellbore resulting from injection.}

(f) A pressure fall-off test at least once every five years unless more frequent

testing is required by the Director based on site specific information;

(g) Testing and monitoring to track the extent of the carbon dioxide plume and

the position of the pressure front by either monitoring for pressure changes

<<in the first formation overlying the confining zone >>or using indirect,

geophysical techniques (e.g., seismic, electrical, gravity, or electromagnetic

surveys and/or down-hole CO2 detection tools);

{If there are changes in the first formation overlying the confining

zone, the carbon dioxide stream has not been confined.}

<<(h) At the Director's discretion, surface air monitoring and/or soil gas

monitoring to detect movement of carbon dioxide that could endanger a USDW. (1)

The testing and monitoring plan must be based on potential vulnerabilities

Page 16
EPA-HQ-OW-2008-0390-0122

within the area of review; (2) The monitoring frequency and spatial distribution

of surface air monitoring and/or soil gas monitoring must reflect baseline data

and the monitoring plan must include how the proposed monitoring will yield

useful information on the area of review delineation and/or compliance with

standards under 40 CFR 144.12;>>

{Any requirement for surface air monitoring and/or soil gas monitoring is not

warranted. If the purpose is to detect "movement of carbon dioxide that could

endanger a USDW, it would be too late if carbon dioxide were detected in the air

or soil. In addition, levels of ambient carbon dioxide are too variable for

this to be useful. RRC suggests eliminating any potential requirement for

surface air or soil gas monitoring, because formation monitoring should catch

whatever condition might reasonably be expected to be caught by surface or soil

gas monitoring. }

(i) Any additional monitoring, as required by the Director, necessary to

support, upgrade, and improve computational modeling of the area of review

evaluation required under §146.84(b) and to determine compliance with standards

under 40 CFR 144.12; and

(j) A quality assurance and surveillance plan for all testing and monitoring

requirements.

§146.91 Reporting requirements.

The owner or operator must, at a minimum, provide the following reports to the

Director, for each permitted Class VI well:

(a) Semi-annual reports containing:

(1) Any changes to the physical, chemical and other relevant characteristics of

the carbon dioxide stream from the proposed operating data;

(2) Monthly average, maximum and minimum values for injection pressure, flow

rate and volume, and annular pressure;

(3) A description of any event that exceeds operating parameters for annulus

pressure or injection pressure as specified in the permit;

(4) A description of any event which triggers a shutdown device required

pursuant to §146.88(e) and the response taken;

(5) The monthly volume of carbon dioxide stream injected over the reporting

period and project cumulatively;

(6) Monthly annulus fluid volume added; and

(7) The results of monitoring prescribed under §146.90.

(b) Report, within 30 days the results of: (1) Periodic tests of mechanical

integrity; (2) Any other test of the injection well conducted by the permittee

if required by the Director; and (3) Any well workover. 

(c) Owners or operators must submit reports in an electronic format acceptable

to the Director. At the discretion of the Director, other formats may be

accepted.

§146.92 Injection well plugging.

(a) Prior to the well plugging, the owner or operator must flush each Class VI

injection well with a buffer fluid, determine bottomhole reservoir pressure, and

perform a final mechanical integrity test.

(b) Well Plugging Plan. The owner or operator of a Class VI well must prepare,

maintain, and comply with a plan that is acceptable to the Director. The

requirement to maintain and implement an approved plan is directly enforceable

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

plugging plan must be submitted as part of the permit application and must

include the following information:

Page 17
EPA-HQ-OW-2008-0390-0122

(1) Appropriate test or measure to determine bottomhole reservoir pressure; (2)

Appropriate testing methods to ensure mechanical integrity as specified in

§146.89; (3) The type and number of plugs to be used; (4) The placement of each

plug including the elevation of the top and bottom of each plug; (5) The type

and grade and quantity of material to be used in plugging. The material must be

compatible with the carbon dioxide stream; and (6) The method of placement of

the plugs.

(c) Notice of intent to plug. The owner or operator must notify the Director at

least 60 days before plugging of a well. At this time, if any changes have been

made to the original well plugging plan, the owner or operator must also provide

the revised well plugging plan. At the discretion of the Director, a shorter

notice period may be allowed.

(d) Plugging report. Within 60 days after plugging or at the time of the next

semi-annual report (whichever occurs earlier) the owner or operator must submit

a plugging report to the Director. If the semi-annual report is due less than

15 days after completion of plugging, then the report must be submitted within

60 days after plugging. The report must be certified as accurate by the owner or

operator and by the person who performed the plugging operation (if other than

the owner or operator.)

§146.93 Post-injection site care and site closure. (a) The owner or operator of

a Class VI well must prepare, maintain, and comply with a plan for postinjection site care and site closure that meets the requirements of paragraph

(a)(2) of this section and is acceptable to the Director. 

(1) <<The owner or operator must submit the post-injection site care and site

closure plan as a part of the permit application to be approved by the

Director.>>

{Redundant - See 146.82(w).}

(2) The post-injection site care and site closure plan must include the

following information:

(i) The pressure differential between pre-injection and predicted post-injection

pressures in the injection zone; (ii) The predicted position of the carbon

dioxide plume and associated pressure front at site closure as demonstrated in

the AOR evaluation required under §146.84(b); (iii) A description of postinjection monitoring location, methods, and proposed frequency; and (iv) A

proposed schedule for submitting post-injection site care monitoring results to

the Director.

{This should be referenced in 146.82(w).}

(3) Upon cessation of injection, THE OWNER OR OPERATOR MUST either submit an

amended post-injection site care and site closure plan or demonstrate to the

Director through monitoring data and modeling results that no amendment to the

plan is needed.

(4) THE OWNER OR OPERATOR MAY <<May>> modify and resubmit the post-injection

site care and site closure plan for the Director's approval within 30 days of

such change.

(b) THE OWNER OR OPERATOR MUST <<Must>> monitor the site following the cessation

of injection to show the position of the carbon dioxide plume and pressure front

and demonstrate that USDWs are not being endangered.

(1) THE OWNER OR OPERATOR MUST <<Must>> continue to conduct monitoring as

specified in the Director-approved post-injection site care and site closure

plan for THE PERIOD OF TIME <<at least 50 years>> following the cessation of

Page 18
EPA-HQ-OW-2008-0390-0122

injection <<. At the Director's discretion, the monitoring will continue>> until

THE DIRECTOR DETERMINES THAT the geologic sequestration project no longer poses

an endangerment to USDWs.

<<(2) If the owner or operator can demonstrate to the satisfaction of the

Director before 50 years, based on monitoring and other site-specific data, that

the GS project no longer poses an endangerment to USDWs, the Director may

approve an amendment to the post-injection site care and site closure plan to

reduce the frequency of monitoring or may authorize site closure before the end

of the 50-year period.>>

{The period of time an owner or operator is required to conduct post-closure

care monitoring should be based on the ability of the pressure to cause

endangerment of USDWs. A 50-year post-closure care monitoring period is

unprecedented and implies that CO2 presents a greater risk than it does. RRC

suggests that EPA strike the phrase "for at least 50 years" and make the time

for continued monitoring be based on site specific data. }

(3) Prior to authorization for site closure, must submit to the Director a

demonstration, based on monitoring and other site-specific data, that the

<<carbon dioxide plume and >> pressure front have stabilized and that no

additional monitoring is needed to assure that the GS project does not pose an

endangerment to USDWs.

{The carbon dioxide plume will continue to move with other formation fluids -

they are never static. The real test should be whether or not the pressure has

dissipated and the pressure front stabilized to the point that there is no

threat of endangering USDWs.}

<<(4) If such a demonstration cannot be made after the 50-year period, must

submit to the Director a plan to continue post-injection site care.>>

{See comment above.}

(c) Notice of intent for site closure. Must notify the Director at least 120

days before site closure. At this time, if any changes have been made to the

original post-injection site care and site closure plan, THE OWNER OR OPERATOR

must also provide the revised plan. At the discretion of the Director, a shorter

notice period may be allowed.

(d) After the Director has authorized site closure, THE OWNER OR OPERATOR must

plug all monitoring wells in a manner which will not allow movement of injection

or formation fluids that endangers a USDW.

(e) Once the Director has authorized site closure, THE OWNER OR OPERATOR must

submit a site closure report within 90 days that must thereafter be retained at

a location designated by the Director. The report must include:

(1) Documentation of appropriate injection and monitoring well plugging as

specified in §146.92 and paragraph (c) of this section. Must provide a copy of

a survey plat which has been submitted to the local zoning authority designated

by the Director, which indicates the location of the injection well relative to

permanently surveyed benchmarks. <<Must also submit a copy of the plat to the

regional administrator of the appropriate EPA Regional Office>>;

{Why is this necessary? The EPA regional office will have access to all records

at the State. }

(2) Documentation of appropriate notification and information to such State,

local and tribal authorities as have authority over drilling activities to

enable such State and local authorities to impose appropriate conditions on

subsequent drilling activities that may penetrate the injection and confining

zone(s); and (3) Records reflecting the nature, composition and volume of the

Page 19
EPA-HQ-OW-2008-0390-0122

carbon dioxide stream.

(f) THE OWNER OR OPERATOR MUST<<Must>> record a notation on the deed to the

facility property or any other document that is normally examined during title

search that will in perpetuity provide any potential purchaser of the property

the following information:

(1) The fact that land has been used to sequester carbon dioxide;

(2) The name of the State agency, local authority, and/or tribe with which the

survey plat was filed<<, as well as the address of the Regional EPA Office to

which it was submitted>>; and (3) The volume of fluid injected, the injection

zone <<or zones>> into which it was injected, and the period over which

injection occurred.

(g) Must retain for three years following site closure, records collected during

the post-injection site care period. THE OWNER OR OPERATOR MUST <<Must>>

deliver the records to the Director at the conclusion of the retention period,

and the records must thereafter be retained at a location designated by the

Director for that purpose.

§146.94 Emergency and remedial response.

(a) As part of the permit application, THE OWNER OR OPERATOR must provide the

Director with an emergency and remedial response plan that describes actions to

be taken to address movement of the injection or formation fluids that may cause

an endangerment to a USDW during construction, operation, closure and postclosure periods.

{Redundant - See 146.82(X)}

(b) If the owner or operator obtains evidence that the injected carbon dioxide

stream and associated pressure front may cause an endangerment to a USDW, the

owner or operator must:

(1) Immediately cease injection; (2) Take all steps reasonably necessary to

identify and characterize any release; (3) Notify the Director within 24 hours;

and (4) Implement the emergency and remedial response plan approved by the

Director.

(c) The Director may allow the operator to resume injection prior to remediation

if the owner or operator demonstrates that the injection operation will not

endanger USDWs.

(d) Must notify the Director and obtain his approval prior to conducting any

well workover.

Page 20
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 1 of 16

SPECIFIC RULE PROVISIONS

Proposed Subpart A - General Provisions

§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.”

Proposed Subpart D - Authorization by Permit

§144.36 Duration of permits. 

We agree with the proposal to issue permits for UIC wells associated with 

sequestration of CO2 “for the period up to the operating life of the facility.” The 

substantial financial investment in a project makes a permit for the operating like of 

the facility imperitive. 

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.”

Subpart H--Criteria and Standards Applicable to Class VI Wells

§146.81 Applicability.

(a) This subpart establishes criteria and standards for UIC programs to regulate Class VI 

CO2 GS injection wells.

(b) This subpart applies to wells used to inject CO2 specifically for the purpose of GS, i.e., 

the long-term containment of a gaseous, liquid or supercritical CO2 stream in subsurface 

geologic formations.

(c) This subpart applies to owners and operators of permit or rule-authorized Class I 

industrial, Class II, or Class V experimental CO2 injection projects who seek to apply for a 

Class VI geologic sequestration permit for their well or wells. If the Director determines that 

USDWs will not be endangered, such wells are exempt, at the Director's discretion, from the 

casing and cementing requirements at §§146.86(b) and 146.87(a)(1) through (3).

RRC agrees that the Director evaluating a permit application to use existing injection 

wells for geologic sequestration should have the discretion to exempt wells from 

Class I industrial, Class II or Class V wells from the proposed casing and cementing 

requirements of Class VI wells. 
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 2 of 16

(d) Definitions. The following definitions apply to this subpart. To the extent that these 

definitions conflict with those in §146.3 these definitions govern:

Area of review means the region surrounding the GS project that may be impacted by the 

injection activity. The AOR is based on computational modeling that accounts for the 

physical and chemical properties of all phases of the injected CO2 stream.

Carbon dioxide plume means the underground extent, in 3-D, of an injected CO2 stream.

Carbon dioxide stream means CO2 that has been captured from an emission source (e.g., 

a power plant), plus incidental associated substances derived from the source materials and 

the capture process, and any substances added to the stream to enable or improve the 

injection process. This subpart does not apply to any CO2 stream that meets the definition of 

a hazardous waste under 40 CFR part 261.

Confining zone means a geologic formation, group of formations, or part of a formation 

stratigraphically overlying the injection zone that acts as a barrier to fluid movement.

Corrective action means the use of Director approved methods to assure that wells within 

the AOR do not serve as conduits for the movement of fluids into USDWs.

Geologic sequestration means the long-term containment of a gaseous, liquid or 

supercritical carbon dioxide stream in subsurface geologic formations. This term does not 

apply to its capture or transport.

Geologic sequestration project means an injection well or wells used to emplace a CO2

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 3-D extent of the carbon dioxide plume, associated pressure front, 

and displaced brine, as well as the surface area above that delineated region.

RRC suggests adding to the end of the first sentence of the definition of 

Geologic sequestration project, “or another formation, if the Director 

determines that injection into the other formation will not endanger 

USDWs.” 

Injection zone means a geologic formation, group of formations, or part of a formation that 

is of sufficient areal extent, thickness, porosity, and permeability to receive CO2 through a 

well or wells associated with a GS project.

Post-injection site care means appropriate monitoring and other actions (including 

corrective action) needed following cessation of injection to assure that USDWs are not 

endangered as required under §146.93.

Pressure front means the zone of elevated pressure that is created by the injection of 

carbon dioxide into the subsurface. For the purposes of this subpart, the pressure front of a 

carbon dioxide plume refers to a zone where there is a pressure differential sufficient to 

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

Why does this definition need to be different?

Site closure the point/time, as determined by the Director following the requirements 

under §146.93, at which the owner or operator of a GS site is released from post-injection 

site care responsibilities.

Transmissive fault or fracture means a fault or fracture that has sufficient permeability and 

vertical extent to allow fluids to move between formations.

Recommend that the fault or fracture be “known.”

§146.82 Required Class VI permit information.
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 3 of 16

This section sets forth the information which the owner or operator must submit to the 

Director in order to be permitted as a Class VI well. The application for a permit for 

construction and operation of a Class VI well must include the following:

(a) Information required in 40 CFR 144.31(e)(1) - (6);

(b) A map showing the injection well(s) for which a permit is sought and the applicable AOR. 

Within the AOR, the map must show the number, or name and location of all injection wells, 

producing wells, abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, 

State or EPA approved subsurface cleanup sites, surface bodies of water, springs, mines 

(surface and subsurface), quarries, water wells and other pertinent surface features 

including structures intended for human occupancy and roads. The map should also show 

faults, if known or suspected. Only information of public record is required to be included on 

this map;

(c) The AOR based on modeling, using data obtained during logging and testing of the well 

and the formation as required by paragraphs (l), (r), and (s) of this section;

(d) Information on the geologic structure and hydrogeologic properties of the proposed 

storage site and overlying formations, including:

(1) Maps and cross sections of the area of review;

(2) Location, orientation, and properties of known or suspected faults and fractures 

that may transect the confining zone(s) in the area of review and a determination that they

would not interfere with containment;

(3) Information on seismic history including the presence and depth of seismic 

sources and a determination that the seismicity would not interfere with containment;

(4) Data on the depth, areal extent, thickness, mineralogy, porosity, permeability and 

capillary pressure of the injection and confining zone(s); including geology/facies changes 

based on field data which may include geologic cores, outcrop data, seismic surveys, well 

logs, and names and lithologic descriptions;

(5) Geomechanical information on fractures, stress, ductility, rock strength, and in 

situ fluid pressures within the confining zone; and

(6) Geologic and topographic maps and cross sections illustrating regional geology, 

hydrogeology, and the geologic structure of the local area.

(e) A tabulation of all wells within the AOR which penetrate the injection or confining zone(s). 

Such data must include a description of each well's type, construction, date drilled, location, 

depth, record of plugging and/or completion, and any additional information the Director may

require;

Definition of confining zone includes multiple formations. Do not imply that 

multiple confining zones are preferable to one (good) confining zone.

(f) Maps and stratigraphic cross sections indicating the general vertical and lateral limits of 

all USDWs, water wells and springs within the area of review, their positions relative to the 

injection zone(s) and the direction of water movement, where known;

Consistency with definition and use of term in other areas of the rules.

(g) Baseline geochemical data on subsurface formations, including all USDWs in the AOR;

(h) Proposed operating data:

(1) Average and maximum daily rate and volume of the CO2 stream;

(2) Average and maximum injection pressure;

(3) The source of the CO2 stream; and

(4) An analysis of the chemical and physical characteristics of the CO2 stream;
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 4 of 16

(i) The compatibility of the CO2 stream with fluids in the injection zone and minerals in both 

the injection and the confining zone(s), based on the results of the formation testing 

program, and with the materials used to construct the well;

See comment above.

(j) Proposed formation testing program to obtain an analysis of the chemical and physical 

characteristics of the injection zone and confining zone;

(k) Proposed stimulation program and a determination that stimulation will not interfere with 

containment;

(l) The results of the formation testing program as required in paragraph (j) of this section;

(m) Proposed procedure to outline steps necessary to conduct injection operation;

“Proposed procedure to outline steps” does not make sense. Recommend 

“Outline of steps ....”

(n) Schematic or other appropriate drawings of the surface and subsurface construction 

details of the well;

(o) Injection well construction procedures that meet the requirements of §146.86;

(p) Proposed AOR and corrective action plan that meets the requirements under §146.84;

(q) The status of corrective action on wells in the AOR;

(r) All available logging and testing program data on the well required by §146.87;

(s) A demonstration of mechanical integrity pursuant to §146.89;

(t) A demonstration, satisfactory to the Director, that the applicant has met the financial 

responsibility requirements under §146.85;

(u) Proposed testing and monitoring plan required by §146.90;

(v) Proposed injection well plugging plan required by §146.92(b);

(w) Proposed post-injection site care and site closure plan required by §146.93(a);

(x) Proposed emergency and remedial response plan required by §146.94; and

(y) Any other information requested by the Director.

§146.83 Minimum criteria for siting.

(a) Owners and operators of Class VI wells must demonstrate to the satisfaction of the 

Director that the wells will be sited in areas with a suitable geologic system. The geologic 

system must be comprised of:

(1) An injection zone of sufficient areal extent, thickness, porosity, and permeability to 

receive the total anticipated volume of the carbon dioxide stream;

Redundant - simply repeats the definition of “injection zone.” Either take this 

language out of the definition or take it out of here.

(2) A confining zone(s) that is free of transmissive faults or fractures and of sufficient 

areal extent and integrity to contain the injected carbon dioxide stream and displaced 

formation fluids and allow injection at proposed maximum pressures and volumes without 

initiating or propagating fractures in the confining zone(s); and

Redundant. Repeats definition of “confining zone.” Also, implies that the 

confining zone cannot have a single fracture, no matter how small. Much more 

stringent than for Class I hazardous wells.

(b) At the Director's discretion, owners or operators of Class VI wells must identify and 

characterize additional zones that will impede vertical fluid movement, are free of faults and 
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 5 of 16

fractures that may interfere with containment, allow for pressure dissipation, and provide 

additional opportunities for monitoring, mitigation and remediation.

Redundant and unnecessary. Language in definition of “confining zone.”

§146.84 Area of review and corrective action.

(a) The area of review is the region surrounding the geologic sequestration project that may

be impacted by the injection activity. The area of review is based on computational modeling 

that accounts for the physical and chemical properties of all phases of the injected carbon 

dioxide stream.

Redundant - same as the definition of “area of review.”

(b) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan 

to delineate the AOR for a proposed geologic sequestration project, periodically reevaluate 

the delineation, and perform corrective action that meets the requirements of this section at 

a frequency and in a manner that and is acceptable to the Director. As a part of the 

permit application for approval by the Director, the owner or operator must submit an area of 

review and corrective action plan that includes the following information:

(1) The method for delineating the area of review that meets the requirements of 

paragraph (c) of this section, including the model to be used, assumptions that will be made, 

and the site characterization data on which the model will be based;

(2) A description of:

(i) The minimum fixed frequency, not to exceed 10 years, the owner or 

operator proposes to reevaluate the area of review;

(ii) The monitoring and operational conditions that would warrant a 

reevaluation of the area of review prior to the next scheduled reevaluation as determined by

the minimum fixed frequency established in paragraph (b)(2)(i) of this section.

Suggest that there be no minimum fixed frequency for reevaluation of the 

AoR, but that such review be based on site-specific circumstances. 

(II)(iii) How monitoring and operational data (e.g., injection rate and pressure) 

will be used to inform an area of review reevaluation; and

(iv) How corrective action will be conducted to meet the requirements of 

paragraph (d) of this section, including what corrective action will be performed prior to 

injection and what, if any, portions of the area of review will have corrective action addressed 

on a phased basis and how the phasing will be determined; how corrective action will be 

adjusted if there are changes in the area of review; and how the site will be accessed will be 

guaranteed for future corrective action.

Word Choice. Secure rather than guarantee. 

(c) Owners or operators of Class VI wells must perform the following actions to delineate the 

area of review, identify all wells that require corrective action, and perform corrective action 

on those wells:

(1) Predict, using computational modeling, the projected lateral and vertical migration 

of the carbon dioxide plume and formation fluids in the subsurface from the commencement 

of injection activities until the plume movement ceases, pressure differentials sufficient to 

cause the movement of injected fluids or formation fluids into a USDW are no longer 

present, or for after a fixed time period as determined by the Director. The modeling must:

(i) Be based on detailed geologic data collected to characterize the injection 

zone and, confining zone and any additional zones; and anticipated operating data, 
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 6 of 16

including injection pressures, rates and total volumes over the proposed life of the geologic 

sequestration project;

(ii) Take into account relevant any geologic heterogeneities and, data quality, 

and their possible impact on model predictions; and

(iii) Consider potential migration through known faults, fractures, and artificial 

penetrations.

(2) Using methods approved by the Director, identify all known artificial penetrations

through the confining zone, including active and abandoned wells and underground 

mines, in the area of review that may penetrate the confining zone. Provide a description 

of each well's type, construction, date drilled, location, depth, record of plugging and/or 

completion, and any additional information the Director may require; and

(3) Determine which abandoned wells in the AOR have been plugged in a manner 

that prevents the movement of CO2 or formation associated fluids that may endanger 

USDWs.

(d) Owners or operators of Class VI wells must perform corrective action using corrosion 

resistant material, when appropriate, on all wells identified in §146.84(c)(2) in the AOR 

that are determined to need corrective action using methods necessary to prevent the 

movement of fluid into or between USDWs including use of corrosion resistant 

materials, where appropriate.

(e) If monitoring data indicate an endangerment to USDWs, the owner or operator must 

notify the Director and cease operations as required by §146.94.

(f) At the minimum fixed frequency, not to exceed 10 years, as As specified in the AOR 

and corrective action plan, or when monitoring and operational conditions warrant, the owner 

or operator must:

(1) Reevaluate the AOR in the same manner specified in paragraph (c)(1) of this 

section;

(2) Identify all wells in the reevaluated AOR that require corrective action in the same 

manner specified in paragraph (c)(2) of this section;

(3) Perform corrective action on wells requiring corrective action in the reevaluated 

AOR in the same manner specified in paragraph (c)(3) of this section; and

(4) Submit an amended AOR and corrective action plan or demonstrate to the 

Director through monitoring data and modeling results that no change amendment to the 

AOR and corrective action plan is needed.

Appropriate frequency of determining AoR might not be “fixed.” Owner or 

operator might need to reevaluate AoR frequently at first, particularly with 

deep brine formations about which there is little history, and then at expanding 

intervals as more information is known.

(g) The emergency and remedial response plan (as required by §146.94) and a 

demonstration of financial responsibility (as described by §146.85) must account for the 

entire AOR, regardless of whether or not corrective action in the area of review is phased.

§146.85 Financial responsibility.

(a) The owner or operator must demonstrate and maintain financial responsibility and 

resources for corrective action (that meets the requirements of §146.84), injection well 

plugging (that meets the requirements of §146.92), post-injection site care and site closure 
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 7 of 16

(that meets the requirements of §146.93), and emergency and remedial response (that 

meets the requirements of §146.94) in a manner prescribed by the Director until:

(1) The Director receives and approves the completed post-injection site care and 

site closure plan; and

(2) The Director determines that the site has reached the end of the post-injection 

site care period.

(b) The owner or operator must provide to the Director, at a frequency determined by the 

Director, written updates of adjustments to the cost estimate to account for any amendments 

to the AOR and corrective action plan (§146.84), the injection well plugging plan (§146.92), 

and the post-injection site care and site closure plan (§146.93).

(c) The owner or operator must notify the Director of adverse financial conditions such as 

bankruptcy, that may affect the ability to carry out injection well plugging and post-injection 

site care and site closure.

(d) The operator must provide an adjustment of the cost estimate to the Director if the 

Director has reason to believe that the original demonstration is no longer adequate to cover 

the cost of injection well plugging (as required by §146.92) and post-injection site care and 

site closure (as required by §146.93).

§146.86 Injection well construction requirements.

(a) General. The owner or operator must ensure that all Class VI wells are constructed and 

completed to:

(1) Prevent the endangerment of USDWs movement of fluids into or between 

USDWs or into any unauthorized zones;

(2) Permit the use of appropriate testing devices and workover tools; and

(3) Permit continuous monitoring of the annulus space between the injection tubing 

and long string casing.

(b) Casing and Cementing of Class VI Wells.

(1) Casing and cement or other materials used in the construction of each Class VI 

well must have sufficient structural strength and be designed for the operating life of the 

wellgeologic sequestration project. All well materials must be compatible with fluids with 

which the materials may be expected to come into contact and meet or exceed standards 

developed for such materials by the API, ASTM International, or comparable standards 

acceptable to the Director. The casing and cementing program must be designed to prevent 

the movement of fluids into or between USDWs. In order to allow the Director to determine 

and specify casing and cementing requirements, the owner or operator must provide the 

following information:

The threat to the integrity of the casing and cement and other materials is 

greatest during injection, and quickly decreases as the pressure dissipates after 

cessation of injection. 

(i) Depth to the injection zone;

(ii) Injection pressure, external pressure, internal pressure and axial loading;

(iii) Hole size;

(iv) Size and grade of all casing strings (e.g., wall thickness, external 

diameter, nominal weight, length, joint specification and construction material);

(v) Corrosiveness of the carbon dioxide stream, and formation fluids;

(vi) Down-hole temperatures and pressures;

(vii) Lithology of injection and confining zones;

(viii) Type or grade of cement, including additives; and
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 8 of 16

(ix) Quantity, chemical composition, and temperature of the CO2 stream.

Redundant - look at application requirements.

(2) Surface casing must extend through the base of the lowermost USDW above the 

injection zone and be cemented to the surface.

(3) At least one long string casing, using a sufficient number of centralizers, must 

extend to the injection zone and must be cemented by circulating cement to the surface in 

one or more stages.

Circulation of cement unnecessary and more stringent that requirement for 

Class I hazardous waste wells. RRC suggests that it may not be technically 

feasible to cement the full column of one long string casing because the 

formations you likely want to inject into are low-pressure, and typically 

won't hold a full column of cement, making circulation impossible. RRC 

suggests a certain footage of cement, such as 600 ft, and require a bond 

log to verify it. 

(4) Circulation of cement may be accomplished by staging. The Director may

approve an alternative method of cementing in cases where the cement cannot be 

recirculated to the surface, provided the owner or operator can demonstrate by using logs 

that the cement does not allow fluid movement behind the well bore.

(5) Cement and cement additives must be compatible with the CO2 stream and 

formation fluids and of sufficient quality and quantity to maintain integrity over the design life 

of the well geologic sequestration project. The integrity and location of the cement shall be 

verified using technology capable of evaluating cement quality radially and identifying the 

location of channels to ensure that USDWs are not endangered.

See comment above.

(c) Tubing and packer.

(1) All owners or operators of Class VI wells must inject fluids through tubing with a 

packer set at a depth opposite a cemented interval at the location approved by the Director.

(2) In order for the Director to determine and specify requirements for tubing and 

packer, the owners or operators must submit the following information:

(i) Depth of setting;

(ii) Characteristics of the CO2 stream (chemical content, corrosiveness, 

temperature, and density);

(iii) Injection pressure;

(iv) Annular pressure;

(v) Injection rate (intermittent or continuous) and volume of the CO2 stream;

(vi) Size of casing; and

(vii) Tubing tensile, burst, and collapse strengths.

Repetitive - See application requirements

§146.87 Logging, sampling, and testing prior to injection well operation.

(a) During the drilling and construction of a Class VI injection well, the owner or operator 

must run appropriate logs, surveys and tests to determine or verify the depth, thickness, 

porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant 

geologic formations to assure conformance with the injection well construction requirements 

under §146.86, and to establish accurate baseline data against which future measurements 

may be compared. The owner or operator must submit to the Director a descriptive report 
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 9 of 16

prepared by a knowledgeable log analyst that includes an interpretation of the results of 

such logs and tests. At a minimum, such logs and tests must include:

(1) Deviation checks during drilling on all holes constructed by drilling a pilot hole 

which are enlarged by reaming or another method. Such checks must be at sufficiently

frequent intervals to determine the location of the borehole and to assure that vertical 

avenues for fluid movement in the form of diverging holes are not created during drilling; and

(2) Before and upon installation of the surface casing:

(i) Resistivity, spontaneous potential, and caliper logs before the casing is 

installed; and

(ii) A cement bond and variable density log, and a temperature log after the 

casing is set and cemented.

(3) Before and upon installation of the long string casing:

(i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture 

finder logs, and any other logs the Director requires for the given geology before the casing 

is installed; and

(ii) A cement bond and variable density log, and a temperature log after the 

casing is set and cemented.

(4) A series of tests designed to demonstrate the internal and external mechanical 

integrity of injection wells, which may include:

(i) A pressure test with liquid or gas;

(ii) A tracer survey such as oxygen-activation logging;

(iii) A temperature or noise log;

(iv) A casing inspection log, if required by the Director; and

(5) Any alternative methods that provide equivalent or better information and that are 

required of and/or approved of by the Director.

(b) The owner or operator must take and submit to the Director whole cores or sidewall 

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

injection zone(s). The Director may accept cores from nearby wells if the owner or operator 

can demonstrate that core retrieval is not possible and that such cores are representative of 

conditions at the well. The Director may require the owner or operator to core other 

formations in the borehole.

Rule language should be consistent with definitions.

(c) The owner or operator must record the fluid temperature, pH, conductivity, reservoir 

pressure and the static fluid level of the injection zone(s).

(d) At a minimum, the owner or operator must determine or calculate the following 

information concerning the injection and confining zone(s):

(1) Fracture pressure;

(2) Other physical and chemical characteristics of the injection and confining zones; 

and

(3) Physical and chemical characteristics of the formation fluids in the injection zone.

(e) Upon completion, but prior to operation, the owner or operator must conduct the following 

tests to verify hydrogeologic characteristics of the injection zone:

(1) A pump test; or

(2) Injectivity tests.

(f) The owner or operator must provide the Director with the opportunity to witness all logging 

and testing by this subpart. The owner or operator must submit a schedule of such activities 
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 10 of 16

to the Director 30 days prior to conducting the first test and submit any changes to the 

schedule 30 days prior to the next scheduled test.

§146.88 Injection well operating requirements.

(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.

(b) Injection between the outermost casing protecting USDWs and the well bore is 

prohibited.

(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.

(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.

(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.

(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:

(1) Immediately cease injection;

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

a release of the injected carbon dioxide 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.

§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
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 11 of 16

(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, 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.

(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.

(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.

(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.

(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.

§146.90 Testing and monitoring requirements.

The owner or operator of a Class VI well must prepare, maintain, and comply with a testing 

and monitoring plan to verify that the geologic sequestration project is operating as permitted 

and is not endangering USDWs. The testing and monitoring plan must be submitted with 

the permit application, for Director approval, and must include a description of how the 

owner or operator will meet the requirements of this section. Testing and monitoring 

associated with geologic sequestration projects must, at a minimum, include:

(a) Analysis of the carbon dioxide stream with sufficient frequency to yield data 

representative of its chemical and physical characteristics;

(b) Installation and use, except during well workovers as defined in §146.86(d), of 

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;

(c) Corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting 

and other signs of corrosion must be performed on a quarterly basis to ensure that the well 
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 12 of 16

components meet the minimum standards for material strength and performance set forth in 

§146.86(b) by:

(1) Placing coupons of the well construction materials in contact with the carbon 

dioxide stream; or

(2) Routing the carbon dioxide stream through a loop constructed with the material 

used in the well; or

(3) Using an alternative method approved by the Director;

(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:

(1) The location and number of monitoring wells must be based on specific 

information about the geologic sequestration project, including injection rate and volume, 

geology, the presence of artificial penetrations and other factors;

(2) The monitoring frequency and spatial distribution of monitoring wells must be 

based on baseline geochemical data that has been collected under §146.82(a)(6) and any

modeling results in the AOR evaluation required by §146.84(b);

(e) A demonstration of external mechanical integrity pursuant to §146.89(c) at least once per 

year throughout the duration of injection the geologic sequestration project;

Demonstration of external mechanical integrity should not be necessary after 

cessation of injection and (relatively immediate) dissipation of pressure near 

the wellbore resulting from injection.

(f) A pressure fall-off test at least once every five years unless more frequent testing is 

required by the Director based on site specific information;

(g) Testing and monitoring to track the extent of the carbon dioxide plume and the position of 

the pressure front by either monitoring for pressure changes in the first formation 

overlying the confining zone or using indirect, geophysical techniques (e.g., seismic, 

electrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools);

If there are changes in the first formation overlying the confining zone, the 

carbon dioxide stream has not been confined.

(h) At the Director's discretion, surface air monitoring and/or soil gas monitoring to detect 

movement of carbon dioxide that could endanger a USDW.

(1) The testing and monitoring plan must be based on potential vulnerabilities within the area 

of review;

(2) The monitoring frequency and spatial distribution of surface air monitoring and/or soil gas 

monitoring must reflect baseline data and the monitoring plan must include how the 

proposed monitoring will yield useful information on the area of review delineation and/or 

compliance with standards under 40 CFR 144.12;

Any requirement for surface air monitoring and/or soil gas monitoring is not 

warranted. If the purpose is to detect “movement of carbon dioxide that could 

endanger a USDW, it would be too late if carbon dioxide were detected in the 

air or soil. In addition, levels of ambient carbon dioxide are too variable for 

this to be useful. RRC suggests eliminating any potential requirement for 

surface air or soil gas monitoring, because formation monitoring should catch 

whatever condition might reasonably be expected to be caught by surface or 

soil gas monitoring. 
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 13 of 16

(i) Any additional monitoring, as required by the Director, necessary to support, upgrade, and 

improve computational modeling of the area of review evaluation required under §146.84(b) 

and to determine compliance with standards under 40 CFR 144.12; and

(j) A quality assurance and surveillance plan for all testing and monitoring requirements.

§146.91 Reporting requirements.

The owner or operator must, at a minimum, provide the following reports to the Director, for 

each permitted Class VI well:

(a) Semi-annual reports containing:

(1) Any changes to the physical, chemical and other relevant characteristics of the 

carbon dioxide stream from the proposed operating data;

(2) Monthly average, maximum and minimum values for injection pressure, flow rate 

and volume, and annular pressure;

(3) A description of any event that exceeds operating parameters for annulus 

pressure or injection pressure as specified in the permit;

(4) A description of any event which triggers a shutdown device required pursuant to 

§146.88(e) and the response taken;

(5) The monthly volume of carbon dioxide stream injected over the reporting period 

and project cumulatively;

(6) Monthly annulus fluid volume added; and

(7) The results of monitoring prescribed under §146.90.

(b) Report, within 30 days the results of:

(1) Periodic tests of mechanical integrity;

(2) Any other test of the injection well conducted by the permittee if required by the 

Director; and

(3) Any well workover.

(c) Owners or operators must submit reports in an electronic format acceptable to the 

Director. At the discretion of the Director, other formats may be accepted.

§146.92 Injection well plugging.

(a) Prior to the well plugging, the owner or operator must flush each Class VI injection well 

with a buffer fluid, determine bottomhole reservoir pressure, and perform a final mechanical 

integrity test.

(b) Well Plugging Plan. The owner or operator of a Class VI well must prepare, maintain, 

and comply with a plan that is acceptable to the Director. The requirement to maintain and 

implement an approved plan is directly enforceable regardless of whether the requirement is 

a condition of the permit. The well plugging plan must be submitted as part of the permit 

application and must include the following information:

(1) Appropriate test or measure to determine bottomhole reservoir pressure;

(2) Appropriate testing methods to ensure mechanical integrity as specified in 

§146.89;

(3) The type and number of plugs to be used;

(4) The placement of each plug including the elevation of the top and bottom of each 

plug;

(5) The type and grade and quantity of material to be used in plugging. The material 

must be compatible with the carbon dioxide stream; and

(6) The method of placement of the plugs.
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 14 of 16

(c) Notice of intent to plug. The owner or operator must notify the Director at least 60 days 

before plugging of a well. At this time, if any changes have been made to the original well 

plugging plan, the owner or operator must also provide the revised well plugging plan. At the 

discretion of the Director, a shorter notice period may be allowed.

(d) Plugging report. Within 60 days after plugging or at the time of the next semi-annual 

report (whichever occurs earlier) the owner or operator must submit a plugging report to the 

Director. If the semi-annual report is due less than 15 days after completion of plugging, 

then the report must be submitted within 60 days after plugging. The report must be certified 

as accurate by the owner or operator and by the person who performed the plugging 

operation (if other than the owner or operator.)

§146.93 Post-injection site care and site closure.

(a) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan 

for post-injection site care and site closure that meets the requirements of paragraph (a)(2) 

of this section and is acceptable to the Director.

(1) The owner or operator must submit the post-injection site care and site 

closure plan as a part of the permit application to be approved by the Director.

Redundant - See 146.82(w).

(2) The post-injection site care and site closure plan must include the following 

information:

(i) The pressure differential between pre-injection and predicted post-injection 

pressures in the injection zone;

(ii) The predicted position of the carbon dioxide plume and associated 

pressure front at site closure as demonstrated in the AOR evaluation required under 

§146.84(b);

(iii) A description of post-injection monitoring location, methods, and 

proposed frequency; and

(iv) A proposed schedule for submitting post-injection site care monitoring 

results to the Director.

This should be referenced in 146.82(w).

(3) Upon cessation of injection, the owner or operator must either submit an 

amended post-injection site care and site closure plan or demonstrate to the Director 

through monitoring data and modeling results that no amendment to the plan is needed.

(4) The owner or operator may May modify and resubmit the post-injection site care 

and site closure plan for the Director's approval within 30 days of such change.

(b) The owner or operator mustMust monitor the site following the cessation of injection to 

show the position of the carbon dioxide plume and pressure front and demonstrate that 

USDWs are not being endangered.

(1) The owner or operator mustMust continue to conduct monitoring as specified in 

the Director-approved post-injection site care and site closure plan for the period of time at 

least 50 years following the cessation of injection. At the Director's discretion, the 

monitoring will continue until the Director determines that the geologic sequestration 

project no longer poses an endangerment to USDWs.

(2) If the owner or operator can demonstrate to the satisfaction of the Director 

before 50 years, based on monitoring and other site-specific data, that the GS project 
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 15 of 16

no longer poses an endangerment to USDWs, the Director may approve an 

amendment to the post-injection site care and site closure plan to reduce the 

frequency of monitoring or may authorize site closure before the end of the 50-year 

period.

The period of time an owner or operator is required to conduct post-closure 

care monitoring should be based on the ability of the pressure to cause 

endangerment of USDWs. A 50-year post-closure care monitoring period is 

unprecedented and implies that CO2 presents a greater risk than it does. 

RRC suggests that EPA strike the phrase “for at least 50 years” and make the 

time for continued monitoring be based on site specific data.

(3) Prior to authorization for site closure, must submit to the Director a demonstration, based 

on monitoring and other site-specific data, that the carbon dioxide plume and pressure 

front have stabilized and that no additional monitoring is needed to assure that the GS 

project does not pose an endangerment to USDWs.

The carbon dioxide plume will continue to move with other formation fluids -

they are never static. The real test should be whether or not the pressure has 

dissipated and the pressure front stabilized to the point that there is no threat 

of endangering USDWs.

(4) If such a demonstration cannot be made after the 50-year period, must submit to 

the Director a plan to continue post-injection site care.

See comment above.

(c) Notice of intent for site closure. Must notify the Director at least 120 days before site 

closure. At this time, if any changes have been made to the original post-injection site care 

and site closure plan, the owner or operator must also provide the revised plan. At the 

discretion of the Director, a shorter notice period may be allowed.

(d) After the Director has authorized site closure, the owner or operator must plug all 

monitoring wells in a manner which will not allow movement of injection or formation fluids 

that endangers a USDW.

(e) Once the Director has authorized site closure, the owner or operator must submit a site 

closure report within 90 days that must thereafter be retained at a location designated by the 

Director. The report must include:

(1) Documentation of appropriate injection and monitoring well plugging as specified 

in §146.92 and paragraph (c) of this section. Must provide a copy of a survey plat which has 

been submitted to the local zoning authority designated by the Director, which indicates the 

location of the injection well relative to permanently surveyed benchmarks. Must also 

submit a copy of the plat to the regional administrator of the appropriate EPA

Regional Office;

Why is this necessary? The EPA regional office will have access to all records 

at the State. 

(2) Documentation of appropriate notification and information to such State, local and 

tribal authorities as have authority over drilling activities to enable such State and local 

authorities to impose appropriate conditions on subsequent drilling activities that may

penetrate the injection and confining zone(s); and

(3) Records reflecting the nature, composition and volume of the carbon dioxide 

stream.
EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Comments of the Railroad Commission of Texas

Attachment

Page 16 of 16

(f) The owner or operator mustMust record a notation on the deed to the facility property

or any other document that is normally examined during title search that will in perpetuity

provide any potential purchaser of the property the following information:

(1) The fact that land has been used to sequester carbon dioxide;

(2) The name of the State agency, local authority, and/or tribe with which the survey

plat was filed, as well as the address of the Regional EPA Office to which it was 

submitted; and

(3) The volume of fluid injected, the injection zone or zones into which it was 

injected, and the period over which injection occurred.

(g) Must retain for three years following site closure, records collected during the postinjection site care period. The owner or operator must Must deliver the records to the 

Director at the conclusion of the retention period, and the records must thereafter be 

retained at a location designated by the Director for that purpose.

§146.94 Emergency and remedial response.

(a) As part of the permit application, the owner or operator must provide the Director with 

an emergency and remedial response plan that describes actions to be taken to address 

movement of the injection or formation fluids that may cause an endangerment to a USDW

during construction, operation, closure and post-closure periods. 

Redundant - See 146.82(X)

(b) If the owner or operator obtains evidence that the injected carbon dioxide stream and 

associated pressure front may cause an endangerment to a USDW, the owner or operator 

must:

(1) Immediately cease injection;

(2) Take all steps reasonably necessary to identify and characterize any release;

(3) Notify the Director within 24 hours; and

(4) Implement the emergency and remedial response plan approved by the Director.

(c) The Director may allow the operator to resume injection prior to remediation if the owner 

or operator demonstrates that the injection operation will not endanger USDWs.

(d) Must notify the Director and obtain his approval prior to conducting any well workover.
Letter ID: 0122 

Commenter: Leslie Savage 

Organization: Railroad Commission of Texas (RRC) 

Letter ID: 0122 Comment ID: 24730 Letter Lines: 29 to 52 

Comment Code: 1330 1.1.3.1 Support use of GS in general 

Comment: Energy (DOE). We share the EPA’s belief that CO2 sequestration has the potential 

to improve air quality. We further believe that the best way to promote 

economical geosequestration of CO2 initially is to link captured CO2 with oil 

reserves, producing increased petroleum recovery efficiencies. 

Texas is a leader in enhanced oil recovery using CO2. Texas possesses an 

extensive oil and gas pipeline infrastructure capable of transporting CO2 to 

various sequestration sites. The first CO2 flood occurred in 1972 in West Texas. 

In 2005, over 160,000 barrels of oil per day were produced with CO2 EOR in 

Texas. The RRC has permitted over 11,200 CO2 injection wells, with over 5,400 of 

those being currently active. The 50 active CO2 enhanced oil recovery projects 

in West Texas represent about 50 percent of total CO2 flooding activity 

worldwide. CO2-driven EOR has grown steadily since 1985 and now accounts for 

over 15 percent of the average yearly oil production in Texas. The oil industry 

has experienced a supply shortage of CO2 over the past few years. Finding new 

sources of CO2 will alleviate that shortfall and result in an increase in oil 

production. The current shortage is about 0.5 billion cubic feet per day, with 

industry consuming the available 1.5 billion cubic feet per day. Increased 

availability of anthropogenic CO2 could accelerate this production. In April of 

2004, the University of Texas Bureau of Economic Geology identified at least 31 

billion barrels of oil in Texas that are recoverable using CO2-driven EOR. 

The RRC has primacy over Class II wells and Class III brine mining wells in 

Texas. Texas has been regulating injection wells since the 1930s. With nearly a 

Individual Response: EPA clarifies that injection of CO2 for the purposes of enhanced oil and 

gas recovery will continue to be permitted under the Class II program, as long as any oil or gas 

production is occurring. The UIC GS requirements will apply to wells used for the purpose of 

long-term GS. 

Please see the remainder of EPA’s responses to this comment for further details. 

For additional information on EPA’s approach to wells that are transitioning from ER to GS, see 

the discussion of Class II wells under “How Does This Rule Affect Existing Injection Wells 

Under the UIC Program?” in the preamble to the final GS rule. 

1
Letter ID: 0122 Comment ID: 24731 Letter Lines: 62 to 98 

Comment Code: 1680 1.3.8 Don't overstate risk, don't stigmatize CO2 

Comment: The Proposal fails to promote and encourage geosequestration of CO2. EPA’s 

stated goals for this proposal are to protect Underground Sources of Drinking 

Water (USDWs) while promoting carbon capture and storage. As the proposal 

stands, the regulations would succeed in protecting USDWs, but would fail to 

successfully promote carbon capture and storage in any significant way. 

Therefore, under the current regulatory scenario, CO2 will continue to be 

released to the atmosphere in greater amounts than would ever leak from a 

properly sited, constructed, and operated CO2 storage facility. One reason for 

the failure is that the proposal overestimates the risk of CO2 sequestration 

and, as a result, creates an overestimated implied liability. Another reason is 

that the Proposal taints the technology by implying that CO2 is a waste. 

Finally, the proposal includes insufficient flexibility to account for the 

geographic variability of potential sites across the country. In summary, the 

RRC is concerned that the Proposal overestimates the risks of CO2 geologic 

sequestration, and creating barriers to rapid implementation of the technology 

rather than encouraging or providing incentives to mobilize large-scale 

projects. 

The Proposal treats CO2 as a waste. The EPA states in the preamble that it has 

not classified CO2 as a waste or a commodity. However, by using the Class I 

waste injection well requirements as the framework for the Class VI 

requirements, the Proposal implies that the CO2 stream is a waste. This 

implication increases not only the potential liability for carbon dioxide 

sequestration, but also the potential liability for anthropogenic CO2 injection 

for the purpose of enhanced recovery of oil and/or natural gas. 

Many provisions of the Proposal address Class VI wells from a waste based 

perspective. With respect to construction, area of review (AoR) and monitoring, 

the Proposal begins with the regulatory framework for Class I non-hazardous 

industrial waste injection well requirements and then adds numerous layers of 

requirements to prevent or detect the escape of CO2 from the injection zone. 

The Proposal excludes CO2 that is a hazardous waste from regulation under the 

Class VI program, but has proposed requirements for Class VI injection wells 

that are more stringent than those for wells used for the injection of hazardous 

waste. RRC strongly disagrees that CO2 buoyancy, corrosivity, and high injection 

volumes for a Class VI project justify a Class I approach. 

Individual Response: EPA clarifies that the purpose of the GS rule is not to promote GS in 

specific settings, nor does it limit injection activities to any specific type of formation, 

geographic region, or depth. The focus of the GS rule is to ensure that, where GS is deployed, it 

is conducted in a manner that is protective of USDWs. 

2
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, EPA expects the tailored permitting, siting, construction, operation, 

monitoring, and post-injection site care requirements in the GS rule to prevent leakage from 

injection formations and protect USDWs. EPA adds that the requirements of the GS rule are 

tailored to the nature of the CO2 itself, and do not address or imply anything regarding the status 

of CO2 as a pollutant, commodity, or waste. EPA does not believe the GS rule creates any 

implication for an increase in potential liability for GS or CO2 injection related to EOR. 

EPA disagrees that the GS rule has “tainted” technology by using the Class I regulations as a 

baseline for the Class VI regulations. Additionally, EPA disagrees that the GS rule provides 

insufficient flexibility to account for geographic variability. EPA has taken a regulatory approach 

that promotes USDW protection, incorporates flexibility or the discretion of the permitting 

authority when appropriate, seeks to limit burden on owners or operators and permitting 

agencies, and provides a foundation for national consistency in permitting of GS projects. For 

example, under the final rule, many of the permit requirements must be established through sitespecific plans (e.g., AoR and corrective action plan, testing and monitoring plan, etc.) developed 

by the owner or operator and approved by the Director. 

Furthermore, EPA recognizes that technologies will evolve and improve over time, and for these 

reasons, the Agency is using an adaptive approach to regulate GS injection. The Agency 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. 

Letter ID: 0122 Comment ID: 24733 Letter Lines: 80 to 98 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment: The Proposal treats CO2 as a waste. The EPA states in the preamble that it has 

not classified CO2 as a waste or a commodity. However, by using the Class I 

waste injection well requirements as the framework for the Class VI 

requirements, the Proposal implies that the CO2 stream is a waste. This 

implication increases not only the potential liability for carbon dioxide 

sequestration, but also the potential liability for anthropogenic CO2 injection 

for the purpose of enhanced recovery of oil and/or natural gas. 

Many provisions of the Proposal address Class VI wells from a waste based 

perspective. With respect to construction, area of review (AoR) and monitoring, 

the Proposal begins with the regulatory framework for Class I non-hazardous 

industrial waste injection well requirements and then adds numerous layers of 

requirements to prevent or detect the escape of CO2 from the injection zone. 

3
The Proposal excludes CO2 that is a hazardous waste from regulation under the 

Class VI program, but has proposed requirements for Class VI injection wells 

that are more stringent than those for wells used for the injection of hazardous 

waste. RRC strongly disagrees that CO2 buoyancy, corrosivity, and high injection 

volumes for a Class VI project justify a Class I approach. 

Individual Response: EPA disagrees that the requirements in the GS rule are too stringent or 

overstate the risk associated with GS. The requirements for Class VI wells are tailored to address 

the unique nature of full-scale CO2 GS, including the injection volumes anticipated for longterm storage, the buoyant and viscous nature of the injectate, and its corrosivity in the presence 

of water. While the Class I requirements formed the basis of many of the specific requirements 

for GS wells, EPA clarifies that the GS rule is tailored to the unique nature of GS. EPA based 

many of the GS requirements on the Class I regulations because, like Class VI wells, Class I 

wells are typically deep and involve waste streams that, if not properly managed, can harm the 

well and lead to contamination. 

EPA also disagrees that the Class VI requirements themselves, or EPA’s consideration of the 

Class I requirements, necessarily have any implications for whether a particular material is a 

RCRA “solid waste” or implicates CERCLA liability, as EPA understands the comment to 

suggest. EPA notes that the GS rule is not promulgated under either of those statutes, and further, 

the applicability of those statutes will not be determined under the SDWA or the terms of the GS 

rule, but rather according to those statutes themselves and any implementing regulations that 

may apply. EPA also notes that the commenter provides no legal analysis explaining why the 

Class VI rule’s requirements alleged implication that CO2 is a waste “increases . . . the potential 

liability for carbon dioxide 

sequestration [or] for anthropogenic CO2 injection for the purpose of enhanced recovery of oil 

and/or natural gas.” EPA adds that liability for Class II wells is outside the scope of this 

rulemaking. 

Letter ID: 0122 Comment ID: 24734 Letter Lines: 100 to 132 

Comment Code: 1680 1.3.8 Don't overstate risk, don't stigmatize CO2 

Comment: The Proposal overestimates the risks of CO2 injection and sequestration. As 

noted in the preamble, naturally occurring CO2 has been trapped in subsurface 

formations for eons. Texas and numerous other states have over 35 years of 

experience in injection of large amounts of CO2 into geologic formations to 

enhanced oil recovery. Over 35 million tons of CO2 are injected annually in more 

than 70 projects in the United States. 

In most cases, with appropriate site selection, construction, monitoring, and 

testing, the risks of CO2 geologic sequestration would be comparable to the 

risks of current activities such as natural gas storage, EOR and deep 

underground disposal of acid gas. In those instances any regulations for Class 

VI wells should reflect more closely UIC Class II standards instead of the more 

4
stringent Class I well standards. 

Both the Class VI and the Class II programs have the same goals - protection of 

USDWs. Yet, EPA’s proposal implies that when the purpose of the injection 

switches from enhanced recovery to sequestration, the risks to USDWs are 

significantly magnified. The RRC does not agree that the volume and duration of 

CO2 injection and placement are sufficiently different in measurable effect on 

the underground to justify the extra layers of requirements. 

However, rather than beginning its CO2 geologic sequestration framework with the 

Class II well program, EPA begins with the framework of Class I non-hazardous 

industrial waste injection well requirements and adds then numerous layers of 

overly redundant requirements to prevent or detect the escape of CO2 from the 

injection zone. The implication seems to be that EPA believes that the Class II 

program is not sufficiently stringent. This implication is a major concern for 

the RRC. 

In addition, the heightened stringency in the proposed requirements for Class VI 

injection wells suggests that geological sequestration of CO2 is as much or more 

dangerous than underground injection of other substances. The Proposal includes 

numerous examples of this heightened stringency: 

Individual Response: As described above, EPA disagrees that the GS rule overstates the risk of 

CO2 injection. While EPA recognizes that industry has decades of experience injecting CO2 for 

EOR and EGR, EPA believes that injection for the primary purpose of long term storage is 

sufficiently different from Class II ER operations and warrants tailored requirements, which is 

why the GS rule used the Class I regulations as its baseline. 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. 

EPA disagrees that the tailored requirements of the GS rule suggest that GS of CO2 is any more 

risky or dangerous than underground injection of other substances. 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. 

Letter ID: 0122 Comment ID: 24735 Letter Lines: 134 to 136 

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

(seeking comment) 

Comment: - The implied recommendation that a geologic sequestration project have more 

than one confining zone is much more stringent than the requirements for Class I 

hazardous waste injection wells. 

5
Individual Response: EPA retains the requirement to identify additional containment/confining 

zones, if required by the Director, as proposed (§146.83(b)). EPA acknowledges that such 

additional zones may not be needed in all circumstances, and clarifies that this requirement is at 

the Director's discretion, based on his or her understanding of a particular site. 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. The Agency's decision is supported 

by commenters representing states, water associations, and an electric utility who assert that 

these requirements promote a flexible, risk-based, site-specific approach to characterizing and 

permitting a site for GS projects, and are intended to improve understanding of the project as a 

whole and promote better modeling of the site. 

Letter ID: 0122 Comment ID: 24736 Letter Lines: 138 to 139 

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

Comment: - The requirement that the long-string casing be cemented to the surface is 

equally as stringent as the Class I hazardous waste well requirements. - Annulus 

Individual Response: EPA clarifies that the requirements for Class VI wells are not necessarily 

more stringent than those for Class I hazardous waste injection wells; rather, they are different. 

For example, Class I hazardous well owner or operators are subject to requirements that are not 

applicable to Class VI wells, such as no migration petitions. 

Letter ID: 0122 Comment ID: 24737 Letter Lines: 139 to 141 

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

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. 

Individual Response: After evaluating the risks and benefits of down-hole shut-off systems and 

considering additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from 

endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or operators of 

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

discretion to mandate automatic down-hole shut-off devices in onshore situations that may 

warrant their use. 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 

6
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. 

Letter ID: 0122 Comment ID: 24738 Letter Lines: 143 to 145 

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment) 

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. 

Individual 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. 

Letter ID: 0122 Comment ID: 24739 Letter Lines: 147 to 149 

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

Comment: - The Proposal’s default 50-year post-injection monitoring period, while 

groundwater monitoring for a Class I hazardous waste injection well is required 

only until the injection zone pressure is such that USDWs cannot be impacted. 

Individual Response: The GS regulations have been tailored to these unique characteristics of 

GS injection wells. EPA developed the Class VI regulations in recognition that the risks posed 

by GS to USDWs are fundamentally different than those associated with current injection 

7
practices regulated by the UIC program, including Class I hazardous waste injection wells. For 

example, CO2 is more buoyant, less viscous (i.e., more mobile), and in some cases more 

corrosive than fluids injected into Class I hazardous waste wells. In addition, the large injection 

volumes anticipated for GS will likely be much greater than current injection practices. Lastly, 

CO2 movement in the subsurface is not as well understood as fluids currently injected under the 

Class I program. 

In combination, these unique characteristics result in CO2 plumes that may be highly mobile in 

the subsurface and move vertically upwards. There will also be some unavoidable levels of 

uncertainty as to the direction and speed of plume movement during and after injection. EPAfunded research by Lawrence Berkeley National Laboratory has shown in preliminary modeling 

studies of ideal basins for GS that pressure perturbations great enough to force saline fluids into 

USDWs may cover large areas compared to current injection projects (10s to 100s km2). This 

research report, entitled "Research Project on CO2 Geological Storage and Groundwater 

Resources: Large-Scale Hydrological Evaluation and Modeling of the Impact on Groundwater 

Systems," is available in the rulemaking docket. EPA developed regulations that would 

appropriately address the larger the area influenced by a GS project, and the resultant, higher 

likelihood that there may be potential faults, fractures, or abandoned wells that could act as a 

conduit for USDW contamination. Furthermore, a level of site-characterization typical for Class 

I hazardous waste injection wells will be extremely difficult over these vast areas. 

Letter ID: 0122 Comment ID: 24740 Letter Lines: 151 to 162 

Comment Code: 1610 1.3.1 Risks to USDWs 

Comment: In nearly every instance where EPA indicates that additional safe-guards are 

necessary, it cites as the reason the chemical characteristics of the CO2 stream 

to be injected and the interaction of the CO2 stream with formation waters and 

strata, the buoyant nature of CO2, and the pressure increases caused by 

injection of very large volumes of CO2. However, buoyancy and chemical 

characteristics of CO2 have been successfully addressed in enhanced recovery 

injection projects using CO2 under the Class II UIC program. Pressure increases 

can be handled by selecting formations that have been depleted and have reduced 

pressures. In those formations for which the pressure has not been reduced as a 

result of production or other activity, the issue of the pressure increase 

resulting from injection of large amounts of CO2 can be addressed by limiting 

the surface injection pressure and adequate monitoring. 

Individual Response: As stated above, EPA acknowledges that industry has decades of 

experience in addressing many of the issues present in GS operations. However, EPA reasonably 

believes that injecting large volumes of CO2 for GS poses unique challenges that, if not properly 

managed, could endanger drinking water sources or have other adverse impacts. EPA believes 

that caution is warranted and has, as a result, developed a new well class with requirements 

tailored to address the unique challenges posed by GS and potential risks associated long-term 

injection of CO2. These requirements include the tailored AoR delineation process per §146.84, 

8
monitoring that is appropriate to GS projects per §146.90, and extended post-injection site care 

per §146.93. 

Letter ID: 0122 Comment ID: 24741 Letter Lines: 164 to 189 

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

Comment: The Proposal does not include sufficient flexibility. Congress mandated, through 

Section 1421(b)(3)(A) of the SDWA, that UIC regulations developed by EPA permit 

or provide consideration of varying geologic, hydrological, or historical 

conditions in different States and in different areas within a State. Thus, 

Congress cautioned EPA against a ‘one-size-fits-all’ regulatory scheme, and 

mandated consideration of local conditions and practices. However, the Proposal 

does not allow State directors to use their expertise and knowledge to account 

for these varying conditions. 

EPA states in the preamble that its reason for selecting Alternative #3 is 

because it ‘provides flexibility while creating a framework of minimum 

requirements to ensure consistency across the nation.’ However, by selecting 

Alternative #3, EPA selected as a starting point the requirements for Class I 

industrial non-hazardous wells. Because of this, the flexibility is restrained 

at the very outset. 

Using as the reason the unknowns and the unique characteristics of CO2 

geosequestration (buoyancy, corrosivity, high injection volumes, etc.), the 

Proposal seems to include the entire slate of possible technologies available to 

complete, operate, monitor and close a UIC well and the injection/confining 

formations. In a few areas, the Proposal provides the Director with discretion 

to set certain application, permit, and monitoring criteria that are appropriate 

to local geologic settings. However, because EPA began with an unnecessarily 

stringent Class I framework, and added numerous other nondiscretionary 

requirements, the flexibility is insufficient. The result is that the Proposal 

is unnecessarily prescriptive and costly. 

Individual Response: EPA agrees that flexibility is important to accommodate the varied 

conditions that may be encountered at GS sites while ensuring the protection of USDWs. 

The technical requirements in Alternative 3 (and the final GS rule) build upon the long-standing 

UIC regulatory framework for deep wells and are appropriately tailored to address the unique 

nature of full-scale CO2 GS, including the volumes of CO2 to be injected, the buoyant and 

mobile nature of the injectate, and its corrosivity in the presence of water. 

The regulation provides flexibility for selection of appropriate sites and target formations (under 

§146.82), well construction specifics (under §146.86), and testing and monitoring regimes (under 

§146.90), provided the owner or operator can demonstrate that the injection and storage will not 

endanger USDWs and that minimum requirements for the site are met. 

9
Letter ID: 0122 Comment ID: 24742 Letter Lines: 191 to 199 

Comment Code: 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: The proposal does not seem to consider CO2 to be sequestered during injection 

for EOR. The first economic CO2 sequestration projects will be associated with 

oil and gas operations, yet the Proposal states that sequestration (and thus, 

Class VI injection) begins only after enhanced recovery of oil or gas has 

stopped. The implication is that the CO2 injected for enhanced recovery is not 

ultimately sequestered upon cessation of injection and production activity. The 

proposal grandfathers the construction of wells permitted as Class V and Class 

II, but requires that the wells comply with all other requirements of Class VI 

wells before injecting CO2 for sequestration. 

Individual Response: EPA recognizes that the oil and gas industry has decades of experience 

injecting CO2 for the purpose of EOR, and that sites used for ER may be suitable for GS and 

may be among the first GS sites. EPA also recognizes that a by-product of ER activities is that a 

certain percentage of the CO2 is trapped in the receiving formation. However, EPA believes that 

injection for the primary purpose of long term storage is sufficiently different from Class II ER 

operations and warrants tailored requirements in order to protect USDWs from endangerment. 

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 EOR projects. 

EPA clarifies that 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. 

Letter ID: 0122 Comment ID: 24743 Letter Lines: 201 to 220 

Comment Code: 5610 2.11.1 Allowing partial primacy for Class VI wells (seeking comment) 

Comment: Delegation of Primacy Congress mandated, through Section 1421(b)(3)(B)(i) of the 

Safe Drinking Water Act (SDWA), that, to the extent feasible, EPA avoid 

promulgating requirements that would unnecessarily disrupt State UIC programs 

already in effect and being enforced in a substantial number of States. 

10
The EPA has indicated that it will delegate the program under Section 1422 of 

the SDWA. The RRC agrees with EPA that it is in the best interest of protecting 

groundwater resources for the geologic sequestration of CO2 to be regulated at 

the state level. However, any requirement by EPA that states accept primacy for 

Class I, III and V wells as a condition for obtaining primacy for Class VI wells 

will create an unreasonable burden upon states. This matter needs to be 

clarified in the rule. In addition, any requirement by EPA that states with 

primacy for Class I, III, and V wells also accept primacy for Class VI wells 

will unnecessarily disrupt the states’ existing UIC programs and will compromise 

the states’ ability to decide how best to administer the state’s program. In 

addition, EPA should allow for split delegation in the Class VI program, as it 

has in Texas for the Class III program, to allow the state to best determine how 

to implement the Class VI program. Furthermore, EPA should not be allowed to 

reopen any state’s primacy over other well classes in order for a state to 

obtain primacy for the Class VI well program. 

Individual Response: EPA agrees with commenters that states should be allowed to obtain 

primacy for Class VI wells independently of other well classes, and will allow independent 

primacy for Class VI wells under §145.1(i) of the final GS rule. Given the potential for CCS 

(encompassing capture, transportation, and geologic sequestration) to be an important part of a 

national priority to address climate change, EPA believes that providing states the flexibility to 

obtain primacy for Class VI wells independently of other well classes can help foster effective 

management of CCS. EPA believes that allowing independent Class VI primacy may encourage 

states to take responsibility for implementation of Class VI regulations and provide for a more 

comprehensive approach to managing CCS projects by promoting the integration of GS activities 

under SDWA into a broader framework for managing CCS. Furthermore, GS operations involve 

ancillary activities (e.g., pipeline operations, pore space ownership, land use rights, and surface 

access) for which states can call upon other authorities that exist at the state level (but outside 

UIC authority) to provide a more comprehensive CCS management approach. 

The Agency believes that it is important for states to use their unique efficiencies to promote 

adoption of this burgeoning and important technology, while assuring that USDWs are protected 

from endangerment through the UIC regulatory framework. EPA believes that, due to the 

importance of implementing an effective, comprehensive, and seamless CCS program, States 

should be provided the flexibility to obtain primacy for Class VI only. 

EPA also believes that allowing states to apply only for Class VI primacy will shorten the 

primacy approval process for states. EPA's willingness to accept independent primacy 

applications for Class VI wells represents a shift in its longstanding policy of discouraging 

"partial primacy." It is very important to note that this shift in policy allowing for Class VI 

primacy does not apply to any other well Class under Section 1422. EPA will continue to 

discourage applications for partial primacy for all other well types under Section 1422. 

EPA clarifies that states should be able to obtain primacy for Class VI wells independent of other 

well classes provided they develop regulations that are at least as stringent as the minimum 

11
Federal requirements (e.g., permitting, inspection, operation, monitoring, and recordkeeping 

requirements) provided in the final GS rule. EPA believes that existing programs can adapt their 

expertise to the new requirements for Class VI wells and will be able to develop a primacy 

application for Class VI wells under section 1422 of SDWA and ensure that their GS programs 

integrate into national climate change priorities and protect USDWs from endangerment. 

In addition, EPA recognizes that some states may not have appropriate geology for sequestering 

CO2, and these states should be able to retain primacy for other well classes without incurring 

the cost and burden of adopting primacy changes to address the new Class VI well requirements. 

EPA also clarifies that a state’s application for primacy for Class VI wells will not affect the 

status of that state’s primacy for other well classes under the UIC program. 

Letter ID: 0122 Comment ID: 24744 Letter Lines: 224 to 238 

Comment Code: 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: 1. EPA should consider creating a subclass within the Class II well 

classification for operators who wish to sequester CO2 in association with 

enhanced recovery of oil or natural gas (with appropriate and necessary 

additional requirements to address any CO2 issues) and allow the Class VI 

injection well program to govern those injection wells used to sequester CO2 in 

formations that are non-productive. 

2. EPA should begin with a reasonable framework (Class II injection wells); 

assure that the rules are flexible enough to consider site-specific 

characteristics and knowledge gained from CO2 history and the ongoing 

demonstration and pilot projects; and that include performance-based 

requirements. Because of Texas’ and other States’ long experience with injection 

operations, the States are in an excellent position to perceive and act upon 

similarities in fluids injected, construction depth, design, operating 

techniques and purposes between its Class II and potential Class VI wells. 

Individual Response: The Agency disagrees that wells injecting CO2 for the primary purpose of 

long term storage should be regulated under Class II requirements or be classified as a sub-class 

of Class II well classification. EPA recognizes that the oil and gas industry has decades of 

experience injecting CO2 for the purpose of EOR, and that sites used for EOR may be suitable 

for GS and may be among the first GS sites. EPA also recognizes that a by-product of EOR 

activities is that a certain percentage of the CO2 is trapped in the receiving formation. 

However, the Agency believes that the nature and risks of CO2 injection for the primary purpose 

of long term storage poses different risks than injection for the primary purpose of ER, and 

therefore has developed new Class VI regulations to address these unique risks in order to 

protect USDWs from endangerment. For example, the volume of CO2 anticipated to be injected 

for long term storage is significantly greater than for EOR operations. Reservoir pressure 

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

12
CO2 and likely having higher pressures within their storage formations than Class II EOR 

projects. EPA believes that injection of CO2 for the primary purpose of enhancing oil and gas 

recovery should remain under the Class II Program. 

EPA has taken a regulatory approach which promotes USDW protection, incorporates flexibility 

or the discretion of the permitting authority when appropriate, seeks to limit burden on owners or 

operators and permitting agencies, and provides a foundation for national consistency in 

permitting of GS projects. For example, under the final rule, many of the permit requirements 

must be established through site-specific plans (e.g., AOR and corrective action plan, testing and 

monitoring plan, etc.) developed by the owner or operator and approved by the Director. 

Consequently EPA expects that owners or operators will consult with the Director as they 

develop, implement, and update these plans. Additionally, the Director has the discretion to 

approve alternatives to the requirements in some cases. For example, the Director may in certain 

situations modify the length of the post-injection site care period or approve an alternative postinjection site care timeframe as part of the permitting process under §146.93, allow the use of 

alternate methods for mechanical integrity testing under §146.89, or grant waivers from the 

requirement to inject below the lowermost USDW under §146.95. 

Letter ID: 0122 Comment ID: 24745 Letter Lines: 240 to 246 

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

Comment: 3. EPA should provide more flexibility in the siting requirements: a. 

acknowledge that some sites offer very good protection when compared to others 

and ease regulatory burden on those sites; b. promote transfer of EOR to 

storage; c. delete the requirement that the confining zone be free of all 

transmissive faults or fractures; d. delete references to multiple confining 

zones; and e. revise the Proposal to allow for site-specific characteristics and 

performance- based determinations. 

Individual Response: The Agency believes that the Class VI requirements balance site-specific 

flexibility with USDW protection. Rather than setting performance or technology-based 

standards for GS projects, EPA is adopting a flexible approach, where operators of GS projects 

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

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

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

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

encourage use of the most appropriate technologies for a particular project. 

Please see the remainder of EPA’s responses to this comment for further details related to 

transitioning of ER projects for GS and confining zone requirements. 

Letter ID: 0122 Comment ID: 24746 Letter Lines: 248 to 249 

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

13
Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment) 

Comment: 4. EPA should provide more flexibiilty in construction, for example, delete the 

requirement that the long string casing be cemented to the surface. 

Individual Response: EPA believes that the requirements for long-string casing are appropriate 

and offer appropriate flexibility: §146.86(b)(3) requires that the long-string casing extend to the 

injection zone and be cemented by circulating cement to the surface in one or more stages. It 

does not, however, specify how cementing would 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, subject to the approval of the 

Director. 

EPA notes that there are many potential ways to meet the requirement, such as the use of staged 

cementing. See the discussion of Class VI well construction requirements in the preamble to the 

final GS rule for additional information. Additionally, EPA is developing guidance on the 

construction of Class VI wells. This guidance will be available on EPA’s website at 

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

EPA adds that other aspects of the rule allow flexibility based on site-specific considerations: 

with their permit applications, owners or operators must submit proposed well construction 

procedures, as specified at §146.82(a)(12), that address the specific drilling and injection 

environment and the chemical and physical nature of the CO2 injected stream. The Director must 

evaluate the appropriateness of the proposed construction based on site-specific information 

about the injection project, including injection pressures, injection and confining zone lithology, 

and information about the carbon dioxide stream, as provided in the final GS rule at 

§146.86(b)(1). 

Letter ID: 0122 Comment ID: 24747 Letter Lines: 251 to 251 

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

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

Individual 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. 

Letter ID: 0122 Comment ID: 24748 Letter Lines: 251 to 255 

14
Comment Code: 1250 1.1.1.4 Flexibility is needed (performance-based standards) 

Comment Code: 3530 2.2.3.1 AoR reevaluation frequency (seeking comment) 

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

operator to demonstrate that CO2 is sequestered, and instead of a 10-year 

default period for reevaluation of the area of review, allow the timing for such 

reevaluation to be determined based on site-specific characteristics and sitespecific monitoring of the CO2 plume and pressure front. 

Individual Response: EPA disagrees that the GS regulation should include performance-based 

standards for AoR calculation. However, EPA believes that consideration of site-specific 

conditions is appropriate for the AoR calculation and reevaluation process. EPA believes that the 

flexibility incorporated into the AoR and corrective action plans and the provision for AoR 

reevaluation as required at §146.84(e) provide for an ongoing review of the site and a dialogue 

between the Director and the owner or operator to ensure that the most appropriate modeling and 

corrective action technologies are used to protect USDWs from endangerment. 

However, EPA believes that setting a minimum reevaluation frequency is appropriate. In the 

final rule, the Agency changed the minimum frequency for the AoR reevaluation at §146.84(e) 

from 10 years to at least every 5 years in the final GS rule. EPA believes that this revised 

frequency addresses commenters' concerns about the inherent uncertainties in modeling CO2 

movement, the emerging nature of GS technology, risk-based targeting of monitoring activities, 

and the unique nature of CO2 GS. 

Letter ID: 0122 Comment ID: 24749 Letter Lines: 257 to 258 

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 

CFR 146.90) 

Comment: 6. EPA should provide more flexibility in the requirements for monitoring, 

testing and reporting. For example, 

Individual Response: EPA agrees that monitoring plans and methods need to be site-specific 

and believes that the monitoring requirements for GS sites at §146.90 provide an appropriate 

level of flexibility in structuring a testing and monitoring plan that protects USDWs from 

endangerment. 

The final regulation provides for flexibility in: 1) methodologies used to collect these data, 2) the 

spatial resolution at which the data should be collected, and 3) how often the data should be 

collected. The number and placement of monitoring wells will be based on site-specific 

information such as the calculated AoR, injection rate and volume, site geology, baseline data, 

and the presence of artificial penetrations within the AoR. In some instances, there may be a 

limited number of options for complying with EPA's minimum requirements. For example, 

monitoring for geochemical changes will require use of monitoring wells and collection of 

groundwater samples for chemical analysis. Many options currently exist for complying with 

other requirements, such as tracking the position of the plume and pressure front within the 

15
injection zone. 

Flexibility is also provided regarding how to monitor for the specific data required by the final 

rule. The testing and monitoring plan is developed by the owner or operator in consultation with 

the Director and is designed to ensure that a detailed, Director-approved document describing 

how monitoring will be conducted during the lifetime of the project exists. 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. 

Letter ID: 0122 Comment ID: 24750 Letter Lines: 258 to 262 

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

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; 

Individual 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. 

16
Letter ID: 0122 Comment ID: 24751 Letter Lines: 264 to 265 

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: b. allow the Director to determine the frequency of mechnical integrity tests, 

with a minimum of 5 years; 

Individual 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. 

Letter ID: 0122 Comment ID: 24752 Letter Lines: 267 to 269 

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking 

comment) 

Comment: c. delete references to air and soil gas monitoring, since such monitoring is a 

case of too little too late - and can result in false positives due to ambient 

variability; and 

Individual 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 

17
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. 

Letter ID: 0122 Comment ID: 24753 Letter Lines: 271 to 272 

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

(seeking comment) 

Comment: d. delete references to tracers, because of the numerous problems discussed in 

the preamble. 

Individual 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. 

Letter ID: 0122 Comment ID: 24754 Letter Lines: 274 to 278 

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

Comment: 7. EPA should provide for performance-based requirements for Closure and Post 

Closure Care. For example, the appropriate length of time for post-injection 

site care should be determined by specific conditions and characteristics of the 

site, and monitoring of the pressure to determine the point at which the 

injection zone pressure is such that USDWs cannot be impacted. 

Individual Response: EPA agrees with commenters that there will be circumstances where it 

can be demonstrated in less than 50 years that the plume and pressure front no longer pose a risk 

of endangerment to USDWs. For this reason, the final GS rule offers owners or operators 

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

18
to shorten or lengthen the PISC timeframe during the PISC period based on site-specific data, 

pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Class 

VI well owner or operator to demonstrate, based on substantial data during the permitting 

process, that an alternative PISC timeframe may be appropriate if it ensures non-endangerment 

of USDWs pursuant to requirements at §146.93(c). 

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

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

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

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

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

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

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

impacts. 

Letter ID: 0122 Comment ID: 24755 Letter Lines: 297 to 303 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

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." } 

Individual 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 

19
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. 

Letter ID: 0122 Comment ID: 24756 Letter Lines: 307 to 312 

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

comment) 

Comment: §144.36 Duration of permits. 

{We agree with the proposal to issue permits for UIC wells associated with 

sequestration of CO2 "for the period up to the operating life of the facility." 

The substantial financial investment in a project makes a permit for the 

operating like of the facility imperitive. } 

Individual Response: EPA agrees with commenters that Class VI permits should be issued for 

the operating life of the GS project. The final rule maintains the lifetime permit provision and 

clarifies that the permit extends through the post-injection site care period (144.36(a)). The rule 

also requires the Director to review the permit at least once every 5 years to determine whether it 

should be modified, revoked and reissued, terminated or a minor modification made as provided 

in §§144.39, 144.40, or 144.41. EPA believes that the iterative process of developing and 

executing the various plans required of GS well operators under the final rule (e.g., for AoR and 

corrective action, testing and monitoring, injection well plugging, post-injection site care, and 

emergency and remedial response) is tailored to the unique aspects of—and is more appropriate 

for–GS than establishing a finite permit duration (e.g., five years as suggested by some 

commenters). EPA adds that the required reviews of the AoR and corrective action plan, the 

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

of the project (at least every 5 years) are preferable to a periodic permit reapplication. The 

iterative process and subsequent plan reevaluations ensure that time and resources are committed 

to the most critical aspects of the permit in preventing endangerment to USDWs. 

Letter ID: 0122 Comment ID: 24757 Letter Lines: 314 to 320 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment: Part 146 UIC Program Criteria and Standards 

§146.5 Classification of injection wells. (f) Class VI. 

20
{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."} 

Individual 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. 

Letter ID: 0122 Comment ID: 24758 Letter Lines: 322 to 340 

Comment Code: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment) 

Comment Code: 2062 1.5.3.1 Grandfathering construction of Class I wells (seeking comment) 

Comment Code: 2064 1.5.3.2 Grandfathering construction of Class II wells (seeking comment) 

Comment Code: 2066 1.5.3.3 Grandfathering construction of Class V wells (seeking comment) 

Comment: Subpart H--Criteria and Standards Applicable to Class VI Wells 

§146.81 Applicability. 

(a) This subpart establishes criteria and standards for UIC programs to regulate 

Class VI CO2 GS injection wells. (b) This subpart applies to wells used to 

inject CO2 specifically for the purpose of GS, i.e., the long-term containment 

of a gaseous, liquid or supercritical CO2 stream in subsurface geologic 

formations. (c) This subpart applies to owners and operators of permit or ruleauthorized Class I industrial, Class II, or Class V experimental CO2 injection 

projects who seek to apply for a Class VI geologic sequestration permit for 

their well or wells. If the Director determines that USDWs will not be 

endangered, such wells are exempt, at the Director's discretion, from the casing 

and cementing requirements at §§146.86(b) and 146.87(a)(1) through (3). 

{RRC agrees that the Director evaluating a permit application to use existing 

injection wells for geologic sequestration should have the discretion to exempt 

wells from Class I industrial, Class II or Class V wells from the proposed 

casing and cementing requirements of Class VI wells. } 

Individual Response: EPA agrees that many Class I, Class II, and Class V experimental 

21
technology wells are designed and constructed to withstand exposure to CO2. The final GS rule 

provides for the construction of these wells to be grandfathered per §146.81(c), 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). EPA clarifies that only the construction requirements are 

grandfathered and that all other Class VI requirements (reporting, monitoring, mechnical 

integrity testing, etc.) must be met following a determination under §146.81(c). 

Letter ID: 0122 Comment ID: 24759 Letter Lines: 372 to 381 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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

Comment: Geologic sequestration project means an injection well or wells used to 

emplace a CO2 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 3-D extent of 

the carbon dioxide plume, associated pressure front, and displaced brine, as 

well as the surface area above that delineated region. 

{RRC suggests adding to the end of the first sentence of the definition of 

Geologic sequestration project, "or another formation, if the Director 

determines that injection into the other formation will not endanger USDWs." } 

Individual Response: EPA disagrees with the suggested edit. However, the Agency has 

modified the final definition of geologic sequestration project at §146.81(d) to read as follows: 

“[A]n injection well or wells used to emplace a carbon dioxide stream 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; or, wells used for geologic sequestration of carbon dioxide that have received an 

aquifer exemption expansion. 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.” 

EPA adds that the final rule contains a new provision for owners or operators to seek a waiver 

from the injection depth requirements, at §146.95. Based on its evaluation of all public 

comments and input on the proposed rule and the Notice of Data Availability and Request for 

Comment, EPA has made many revisions to the Class VI GS rule. Please see the final rule and 

preamble for additional information. 

Letter ID: 0122 Comment ID: 24760 Letter Lines: 392 to 398 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

22
Comment: Pressure front means the zone of elevated pressure that is created by the 

injection of carbon dioxide into the subsurface. For the purposes of this 

subpart, the pressure front of a carbon dioxide plume refers to a zone where 

there is a pressure differential sufficient to cause the movement of 

injected fluids or formation fluids into a USDW. 

{Why does this definition need to be different?} 

Individual Response: The definition of a pressure front is unique to the Class VI GS 

requirements and Subpart H to address the unique nature of CO2 injection for GS, including the 

potential impact a pressure front may have on USDWs. The final definition of pressure front at 

§146.81(d) is unchanged, and reads as follows: “[T]he zone of elevated pressure that is created 

by the injection of carbon dioxide into the subsurface. For the purposes of this subpart, the 

pressure front of a carbon dioxide plume refers to a zone where there is a pressure differential 

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

Based on its evaluation of all public comments and input on the proposed rule and the NODA 

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0122 Comment ID: 24761 Letter Lines: 404 to 407 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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

Comment: Transmissive fault or fracture means a fault or fracture that has sufficient 

permeability and vertical extent to allow fluids to move between formations. 

{Recommend that the fault or fracture be "known."} 

Individual Response: EPA disagrees with the suggested edit. The final definition of 

transmissive fault or fracture at §146.81(d) is unchanged and reads as follows: “[A] fault or 

fracture that has sufficient permeability and vertical extent to allow fluids to move between 

formations.” 

Based on its evaluation of all public comments and input on the proposed rule and the NODA 

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0122 Comment ID: 24762 Letter Lines: 436 to 438 ; 442 to 446 

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

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

geologic data than proposed 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

23
comment) 

Comment: (2) Location, orientation, and properties of known or suspected faults and 

fractures that may transect the confining zone(s) in the area of review and 

a determination that they would not interfere with containment; 

(4) Data on the depth, areal extent, thickness, mineralogy, porosity, 

permeability and capillary pressure of the injection and confining zone(s); 

including geology/facies changes based on field data which may include geologic 

cores, outcrop data, seismic surveys, well logs, and names and lithologic 

descriptions; 

Individual Response: EPA believes that the plural for injection zone(s) should be retained in the 

Final Rule in recognition of the fact that more than one injection zone may be used at some GS 

sites. EPA believes that in some geologic settings, the presence and identification of additional 

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

improve USDW protection. These formations could further impede vertical fluid movement, 

allow for pressure dissipation, and provide additional sites for monitoring, mitigation, and 

remediation, while also affording the greatest protection of USDWs from endangerment. While 

other countries may not require such additional protection, EPA believes that providing the 

Director this additional discretion is an important element of assuring that GS activities will not 

endanger USDWs. 

Please see the final rule and the discussion of geologic site characterization in the preamble for 

additional information. 

Letter ID: 0122 Comment ID: 24763 Letter Lines: 452 to 459 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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

Comment: (e) A tabulation of all wells within the AOR which penetrate the injection or 

confining zone(s). Such data must include a description of each well's type, 

construction, date drilled, location, depth, record of plugging and/or 

completion, and any additional information the Director may require; 

{Definition of confining zone includes multiple formations. Do not 

imply that multiple confining zones are preferable to one (good) 

confining zone.} 

Individual Response: EPA disagrees with the suggested edit. The final language in §146.82 is 

unchanged. EPA retains the requirement to identify additional containment/confining zones, if 

required by the Director, as proposed in §146.83(b). EPA acknowledges that such additional 

zones may not be needed in all circumstances, and clarifies that this requirement is at the 

Director's discretion, based on his or her understanding of a particular site. EPA believes that, in 

some situations, the presence of additional confining and containment zones above the primary 

24
(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. The Agency's decision is supported by 

commenters representing states, water associations, and an electric utility who assert that these 

requirements promote a flexible, risk-based, site-specific approach to characterizing and 

permitting a site for GS projects, and would improve understanding of the project as a whole and 

promote better modeling of the site. 

Additionally, the Agency has modified the final definition of confining zone to read as follows: 

“[A] geologic formation, group of formations, or part of a formation stratigraphically overlying 

the injection zone that acts as barrier to fluid movement. For Class VI wells operating under an 

injection depth waiver, confining zone means a geologic formation, group of formations, or part 

of a formation stratigraphically overlying and underlying the injection zone.” 

Based on its evaluation of all public comments and input on the proposed rule and the NODA 

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0122 Comment ID: 24764 Letter Lines: 461 to 466 

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

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

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: (f) Maps and stratigraphic cross sections indicating the general vertical and 

lateral limits of all USDWs, water wells and springs within the area of review, 

their positions relative to the injection zone(s) and the direction of water 

movement, where known; 

{Consistency with definition and use of term in other areas of the rules.} 

Individual Response: EPA believes that the plural for injection zone(s) should be retained in the 

Final Rule in recognition of the fact that characterizing more than one injection zone may be 

necessary at some GS sites. EPA believes that in some geologic settings, the presence and 

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

confining zone can improve USDW protection. These formations could further impede vertical 

fluid movement, allow for pressure dissipation, and provide additional sites for monitoring, 

mitigation, and remediation, while also affording the greatest protection of USDWs from 

endangerment. EPA believes that providing the Director this additional discretion is an important 

element of assuring that GS activities will not endanger USDWs. 

Please see the final rule and the discussion of geologic site characterization in the preamble for 

additional information. 

25
Letter ID: 0122 Comment ID: 24765 Letter Lines: 478 to 483 

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

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

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: (i) The compatibility of the CO2 stream with fluids in the injection zone and 

minerals in both the injection and the confining zone(s), based on the 

results of the formation testing program, and with the materials used to 

construct the well; 

{See comment above.} 

Individual Response: The final rule will allow the Director to require more than one confining 

zone; therefore, EPA did not make the suggested change. 

Please see the final rule and the discussion of geologic site characterization in the preamble for 

additional information. 

Letter ID: 0122 Comment ID: 24766 Letter Lines: 491 to 495 

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

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

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: (m) Proposed procedure to outline steps necessary to conduct injection 

operation; 

{"Proposed procedure to outline steps" does not make sense. Recommend "Outline 

of steps ...."} 

Individual Response: EPA disagrees that the suggested edit provides more clarity to the 

requirements and has retained the language as proposed. Additionally, similar language is used 

for other UIC well classes and the regulated community and permitting officials are familiar with 

the terms. 

Please see the final rule and the discussion of geologic site characterization in the preamble for 

additional information. 

Letter ID: 0122 Comment ID: 24767 Letter Lines: 522 to 527 

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

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

26
Comment: (1) An injection zone of sufficient areal extent, thickness, porosity, and 

permeability to receive the total anticipated volume of the carbon dioxide 

stream; 

{Redundant - simply repeats the definition of "injection zone." Either take 

this language out of the definition or take it out of here.} 

Individual Response: EPA acknowledges the comment. For consistency, §146.83(a)(1) includes 

the definition of injection zone. EPA clarifies that §146.83 identifies the specific criteria that 

owners or operators must meet to demonstrate that a GS site is suitable for GS. 

Letter ID: 0122 Comment ID: 24768 Letter Lines: 529 to 537 

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

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

trapping mechanism) 

Comment: (2) A confining zone(s) that is free of transmissive faults or fractures and 

of sufficient areal extent and integrity to contain the injected carbon dioxide 

stream and displaced formation fluids and allow injection at proposed maximum 

pressures and volumes without initiating or propagating fractures in the 

confining zone(s); and 

{Redundant. Repeats definition of "confining zone." Also, implies that the 

confining zone cannot have a single fracture, no matter how small. Much more 

stringent than for Class I hazardous wells.} 

Individual Response: EPA believes that the plural for injection zone(s) should be retained in the 

Final Rule in recognition of the fact that characterizing more than one injection zone may be 

necessary at some GS sites. EPA believes that in some geologic settings, the presence and 

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

confining zone can improve USDW protection. These formations could further impede vertical 

fluid movement, allow for pressure dissipation, and provide additional sites for monitoring, 

mitigation, and remediation, while also affording the greatest protection of USDWs from 

endangerment. While other countries may not require such additional protection, EPA believes 

that providing the Director this additional discretion is an important element of assuring that GS 

activities will not endanger USDWs. 

Letter ID: 0122 Comment ID: 24769 Letter Lines: 539 to 545 

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

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

(seeking comment) 

27
Comment: (b) At the Director's discretion, owners or operators of Class VI wells must 

identify and characterize additional zones that will impede vertical fluid 

movement, are free of faults and fractures that may interfere with containment, 

allow for pressure dissipation, and provide additional opportunities for 

monitoring, mitigation and remediation. 

{Redundant and unnecessary. Language in definition of "confining zone."} 

Individual Response: EPA retains the requirement to identify additional containment/confining 

zones, if required by the Director, as proposed (§146.83(b)). EPA acknowledges that such 

additional zones may not be needed in all circumstances, and clarifies that this requirement is at 

the Director's discretion, based on his or her understanding of a particular site. 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. The Agency's decision is supported 

by commenters representing states, water associations, and an electric utility who assert that 

these requirements promote a flexible, risk-based, site-specific approach to characterizing and 

permitting a site for GS projects, and are intended to improve understanding of the project as a 

whole and promote better modeling of the site. 

Letter ID: 0122 Comment ID: 24770 Letter Lines: 547 to 554 

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

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

Comment: §146.84 Area of review and corrective action. 

(a) The area of review is the region surrounding the geologic sequestration 

project that may be impacted by the injection activity. The area of review is 

based on computational modeling that accounts for the physical and chemical 

properties of all phases of the injected carbon dioxide stream. 

{Redundant - same as the definition of "area of review."} 

Individual Response: Based on review of all public comments on the AoR definition at 

146.84(a), the Agency has modified it to read as follows: The region surrounding the geologic 

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

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

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

characterization, monitoring, and operational data. 

Letter ID: 0122 Comment ID: 24771 Letter Lines: 556 to 562 

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

28
Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action 

plan 

Comment: (b) The owner or operator of a Class VI well must prepare, maintain, and comply 

with a plan to delineate the AOR for a proposed geologic sequestration project, 

periodically reevaluate the delineation, and perform corrective action that 

meets the requirements of this section AT A FREQUENCY AND IN A MANNER THAT 

and is acceptable to the Director. As a part of the permit application 

for approval by the Director, the owner or operator must submit an area of 

review and corrective action plan that includes the following information: 

Individual Response: EPA disagrees with the suggested change, and is retaining the approach 

of setting a minimum fixed frequency for reevaluating the AoR but has, based on commenters' 

input, changed the frequency from 10 years to at least every 5 years, as specified in §146.84(e). 

EPA agrees with commenters that site-specific information is an important factor in determining 

an appropriate AoR reevaluation frequency, and adds that the owner or operator's AoR and 

corrective action plan must describe the minimum fixed frequency for reevaluating the AoR and 

the site-specific conditions on which this frequency is based. EPA adds that the Director will 

evaluate the proposed plan in connection with a review of a vast amount of geologic and 

proposed operating data in determining whether to approve the plan. EPA is developing guidance 

on recommended approaches for preparing all of the required GS project plans, which will 

address considerations for determining an appropriate AoR reevaluation schedule. The guidance 

will be available on EPA's web site, at 

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

Letter ID: 0122 Comment ID: 24772 Letter Lines: 569 to 576 

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

Comment Code: 3530 2.2.3.1 AoR reevaluation frequency (seeking comment) 

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action 

plan 

Comment: (2) A description of: (i) The minimum fixed frequency, not to exceed 10 years, 

the owner or operator proposes to reevaluate the area of review; (ii) The 

monitoring and operational conditions that would warrant a reevaluation of the 

area of review prior to the next scheduled reevaluation as determined by the 

minimum fixed frequency established in paragraph (b)(2)(i) of this section. 

{Suggest that there be no minimum fixed frequency for reevaluation of the AoR, 

but that such review be based on site-specific circumstances. } 

Individual Response: EPA believes that periodic AoR reevaluation at a set frequency of at least 

every 5 years is necessary to ensure protection of USDWs from endangerment and address the 

uncertainties inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure 

that a deliberate effort is made to verify, based on monitoring and operational data, that the CO2 

plume is moving within the subsurface as predicted. EPA believes that less frequent 

29
reevaluations may not be sufficient to appropriately model plume and pressure front movement, 

establish conditions for corrective action, and ensure protection of USDWs from endangerment. 

EPA clarifies that if site monitoring data agrees with the existing AoR delineation, a model 

recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration 

that the current AoR delineation is adequate based on site monitoring data. 

Letter ID: 0122 Comment ID: 24773 Letter Lines: 578 to 589 

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

Comment Code: 3400 2.2.2 Corrective Action 

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action 

plan 

Comment: (II)(iii) How monitoring and operational data (e.g., injection rate and 

pressure) will be used to inform an area of review reevaluation; and 

(iv) How corrective action will be conducted to meet the requirements of 

paragraph (d) of this section, including what corrective action will be 

performed prior to injection and what, if any, portions of the area of review 

will have corrective action addressed on a phased basis and how the phasing will 

be determined; how corrective action will be adjusted if there are changes in 

the area of review; and how THE site WILL BE accessed will be guaranteed for 

future corrective action. 

{Word Choice. Secure rather than guarantee. } 

Individual Response: The purpose of the corrective action requirement at §146.84(d) is to 

ensure that all wells in the AoR that have the potential to cause the movement of CO2 or other 

fluids into or between USDWs receive appropriate corrective action. In general, to meet this 

requirement, the owner or operator will mostly likely need to obtain the right of access to wells 

that may require corrective action, and demonstrate they have done this in their proposed AoR 

and corrective action plan. For this reason, the owner or operator must describe in the AoR and 

corrective action plan how site access will be guaranteed for future corrective action, as specified 

in §146.84(b)(2)(iv). The final rule retains the requirement as proposed. 

Letter ID: 0122 Comment ID: 24774 Letter Lines: 595 to 600 

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

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

Comment: (1) Predict, using computational modeling, the projected lateral and vertical 

migration of the carbon dioxide plume and formation fluids in the subsurface 

from the commencement of injection activities until the plume movement ceases, 

pressure differentials sufficient to cause the movement of injected fluids or 

30
formation fluids into a USDW are no longer present, or FOR after a fixed 

time period as determined by the Director. The modelINGmust: 

Individual Response: EPA has clarified this language in the final rule. It now reads, “Predict, 

using existing site characterization, monitoring and operational data, and computational 

modeling, the projected lateral and vertical migration of the carbon dioxide plume and formation 

fluids in the subsurface from the commencement of injection activities until the plume 

movement ceases, until pressure differentials sufficient to cause the movement of injected fluids 

or formation fluids into a USDW are no longer present, or until the end of a fixed time period as 

determined by the Director.” 

Letter ID: 0122 Comment ID: 24775 Letter Lines: 602 to 609 

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

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

Comment: (i) Be based on detailed geologic data collected to characterize the injection 

zone AND, confining zone and any additional zones; and anticipated 

operating data, including injection pressures, rates and total volumes over the 

proposed life of the geologic sequestration project; 

(ii) Take into account RELEVANT any geologic heterogeneities AND, data 

quality, and their possible impact on model predictions; and 

(iii) Consider potential migration through KNOWN faults, fractures, and 

artificial penetrations. 

Individual Response: The final rule retains this requirement as proposed, except that 

146.84(c)(1)(ii) also requires owners or operators to take into account other discontinuities in 

addition to geologic heterogeneities. 

EPA disagrees that only the injection and confining zones should be included in AoR modeling 

of GS sites. EPA believes that the modeling should also take into account the possibility of 

displaced fluids or brines caused by a lateral and/or vertical pressure plume, and therefore it may 

be necessary to include additional zones along with the confining/injection zones to ensure the 

integrity of the confining zone and ultimately protect a USDW from endangerment. 

Letter ID: 0122 Comment ID: 24776 Letter Lines: 611 to 616 

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

Comment Code: 3420 2.2.2.1 Scope of the inventory process (e.g., reliance on publicly 

available information, depth of wells) 

Comment: (2) Using methods approved by the Director, identify all KNOWN ARTIFICIAL 

penetrations THROUGH THE CONFINING ZONE, including active and abandoned wells 

and underground mines, in the area of review that may penetrate the confining 

zone. Provide a description of each well's type, construction, date drilled, 

31
location, depth, record of plugging and/or completion, and any additional 

information the Director may require; and 

Individual Response: EPA is retaining this requirement as proposed. EPA agrees with 

commenters that, for most GS sites, relying on database and other public records searches (i.e., 

of "known" artificial penetrations) will be sufficient to meet the requirements at §146.84(c)(2). 

However, the Agency recognizes that there may be situations where additional surveys or 

research to locate wells may be appropriate. For example, there may be cases where the Director 

may determine that ground or airborne surveys for wells are appropriate, e.g., if there is reason to 

believe, based on knowledge of the site or of available data, that the incompleteness of 

information on known wells could compromise USDW protection from endangerment. In order 

to preserve the Director's discretion to require an operator to supplement a records search, EPA 

did not make the suggested change. 

Letter ID: 0122 Comment ID: 24777 Letter Lines: 618 to 620 

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

Comment Code: 3400 2.2.2 Corrective Action 

Comment: (3) Determine which abandoned wells in the AOR have been plugged in a manner 

that prevents the movement of CO2 or FORMATION associated fluids that may 

endanger USDWs. 

Individual Response: EPA clarifies that the term "associated fluids" as proposed in 

§146.84(c)(3) refers to formation fluids, other injectates, etc. that may be present in the 

subsurface and affect movement of the CO2 plume and/or pressure front. EPA believes this 

terminology would incorporate any fluids in the subsurface that could potentially move through 

artificial penetrations and affect USDWs. EPA has revised the language at §146.84(c)(3) to read, 

"... carbon dioxide or other fluids that may endanger USDWs..." 

Letter ID: 0122 Comment ID: 24778 Letter Lines: 622 to 626 

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

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

cements) 

Comment: (d) Owners or operators of Class VI wells must perform corrective action USING 

CORROSION RESISTANT MATERIAL, WHEN APPROPRIATE, on all wells IDENTIFIED 

IN 

§146.84(C)(2) in the AOR that are determined to need corrective action using 

methods necessary to prevent the movement of fluid into or between USDWs 

including use of corrosion resistant materials, where appropriate. 

Individual Response: EPA revised the text at §146.84(d) to require the use of materials that are 

"compatible with the carbon dioxide stream." EPA believes this language change addresses 

32
commenters' concerns and is also consistent with other language regarding materials 

requirements in the GS rule. 

Letter ID: 0122 Comment ID: 24779 Letter Lines: 631 to 633 

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

Comment Code: 3500 2.2.3 Area of Review Reevaluation (seeking comment) 

Comment: (f) At the minimum fixed frequency, not to exceed 10 years, as AS specified 

in the AOR and corrective action plan, or when monitoring and operational 

conditions warrant, the owner or operator must: 

Individual Response: EPA believes that periodic AoR reevaluation at a set frequency is 

necessary to ensure protection of USDWs from endangerment and address the uncertainties 

inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure that a 

deliberate effort is made to verify, based on monitoring and operational data, that the CO2 plume 

is moving within the subsurface as predicted. EPA believes that less frequent reevaluations may 

not be sufficient to appropriately model plume and pressure front movement, establish conditions 

for corrective action, and ensure protection of USDWs from endangerment. 

EPA clarifies that if site monitoring data agrees with the existing AoR delineation, a model 

recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration 

that the current AoR delineation is adequate based on site monitoring data. 

Based on the comments received (including those by water associations, an energy company, 

associations, industries, states, and environmental groups), EPA has changed the minimum 

frequency for the AoR reevaluation from 10 years to at least every 5 years. EPA believes that 

this revised frequency addresses commenters' concerns about the inherent uncertainties in 

modeling CO2 movement, the emerging nature of GS technology, risk-based targeting of 

monitoring activities, and the unique nature of CO2 GS. 

Letter ID: 0122 Comment ID: 24780 Letter Lines: 642 to 649 

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

Comment Code: 3500 2.2.3 Area of Review Reevaluation (seeking comment) 

Comment: (4) Submit an amended AOR and corrective action plan or demonstrate to the 

Director through monitoring data and modeling results that no CHANGE amendment 

to the AOR and corrective action plan is needed. 

{Appropriate frequency of determining AoR might not be "fixed." Owner or 

operator might need to reevaluate AoR frequently at first, particularly with 

deep brine formations about which there is little history, and then at expanding 

intervals as more information is known.} 

33
Individual Response: EPA agrees that site-specific factors should be considered in the 

reevaluation schedule, and notes that the AoR and corrective action plan must specify the sitespecific monitoring and operational conditions that warrant reevaluation, as specified in 

§146.84(b)(2)(ii). In addition, the Director has discretion to require more frequent AoR 

reevaluation if he or she has reason to believe, based on site-specific information, that a five-year 

reevaluation schedule is not sufficiently protective of USDWs. However, EPA believes that 

setting a minimum reevaluation frequency is appropriate. In the final rule, the Agency changed 

the minimum frequency for the AoR reevaluation at §146.84(e) from 10 years to at least every 5 

years in the final GS rule. EPA believes that this revised frequency addresses commenters' 

concerns about the inherent uncertainties in modeling CO2 movement, the emerging nature of 

GS technology, risk-based targeting of monitoring activities, and the unique nature of CO2 GS. 

Letter ID: 0122 Comment ID: 24781 Letter Lines: 683 to 690 

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

Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 

146.86) 

Comment: §146.86 Injection well construction requirements. (a) General. The owner or 

operator must ensure that all Class VI wells are constructed and completed to: 

(1) Prevent the ENDANGERMENT OF USDWs movement of fluids into or between USDWs 

or into any unauthorized zones; 

(2) Permit the use of appropriate testing devices and workover tools; and 

(3) Permit continuous monitoring of the annulus space between the injection 

tubing and long string casing. 

Individual Response: EPA disagrees with the suggested edit. EPA believes that protection of 

USDWs from endangerment and prevention of fluid movement between formations is 

paramount, and believes that the language as proposed regarding preventing fluid movement is 

more specific and protective. 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. 

Letter ID: 0122 Comment ID: 24782 Letter Lines: 692 to 707 

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

Comment Code: 3860 2.3.3 Well component degradation 

Comment: (b) Casing and Cementing of Class VI Wells. 

(1) Casing and cement or other materials used in the construction of each Class 

VI well must have sufficient structural strength and be designed for the 

OPERATING life of the WELLgeologic sequestration project. All well 

34
materials must be compatible with fluids with which the materials may be 

expected to come into contact and meet or exceed standards developed for such 

materials by the API, ASTM International, or comparable standards acceptable to 

the Director. The casing and cementing program must be designed to prevent 

the movement of fluids into or between USDWs. In order to allow the Director 

to determine and specify casing and cementing requirements, the owner or 

operator must provide the following information: 

{The threat to the integrity of the casing and cement and other materials is 

greatest during injection, and quickly decreases as the pressure dissipates 

after cessation of injection. } 

Individual Response: EPA disagrees that the casing, cement or other materials should only be 

designed for the period of the injection process, rather than the life of the sequestration project. 

GS projects are anticipated to have long life spans in comparison to other types of deep injection 

wells. Not only must Class VI wells be able to function safely and properly over the lifespan of 

the GS project, but they must be constructed such that USDWs remain protected after well 

plugging. The requirements at §146.86 will ensure that the well can maintain integrity 

throughout the proposed life span of the project, including after the injection well is plugged and 

through post-injection site care period and beyond. While the risk profile of a GS site will 

decrease following cessation of injection, EPA believes that Class VI wells must be designed to 

protect USDWs from endangerment for the life of the project. Furthermore, rigorous casing and 

cementing help ensure that the Class VI well will not serve as a conduit for movement of fluids 

associated with future injection operations. 

Letter ID: 0122 Comment ID: 24783 Letter Lines: 709 to 721 

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

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment) 

Comment: (i) Depth to the injection zone; 

(ii) Injection pressure, external pressure, internal pressure and axial loading; 

(iii) Hole size; 

(iv) Size and grade of all casing strings (E.G., wall thickness, external 

diameter, nominal weight, length, joint specification and construction 

material); 

(v) Corrosiveness of the carbon dioxide stream, and formation fluids; 

(vi) Down-hole temperatures AND PRESSURES; 

(vii) Lithology of injection and confining zones; 

(viii) Type or grade of cement, INCLUDING ADDITIVES; and 

(ix) Quantity, chemical composition, and temperature of the CO2 stream. 

{Redundant - look at application requirements.} 

Individual Response: EPA agrees with the suggestion that §146.86(b)(1)(viii) be revised to also 

address cement additives. In the final GS rule, the subparagraph reads as follows: "Type or grade 

35
of cement and cement additives." 

EPA clarifies that information on down-hole pressures is required at §146.86(b)(1)(ii). 

Letter ID: 0122 Comment ID: 24784 Letter Lines: 723 to 724 

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

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

Comment: (2) Surface casing must extend through the base of the lowermost USDW ABOVE 

THE 

INJECTION ZONE and be cemented to the surface. 

Individual Response: EPA disagrees with the suggested edit. 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. 

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. 

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 Class VI 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. EPA believes that, given the possibility for Class VI wells to 

operate under injection depth waivers, the requirement that surface casing must extend through 

the base of the lowermost USDW is important for USDW protection. 

Letter ID: 0122 Comment ID: 24785 Letter Lines: 726 to 735 

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

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

Comment: (3) At least one long string casing, using a sufficient number of centralizers, 

must extend to the injection zone and must be cemented by circulating cement to 

the surface in one or more stages. 

{Circulation of cement unnecessary and more stringent that requirement for Class 

I hazardous waste wells. RRC suggests that it may not be technically feasible 

to cement the full column of one long string casing because the formations you 

likely want to inject into are low-pressure, and typically won't hold a full 

36
column of cement, making circulation impossible. RRC suggests a certain footage 

of cement, such as 600 ft, and require a bond log to verify it. } 

Individual Response: EPA believes that the construction requirements at §146.86 offer 

flexibility to the owner or operator to propose well construction procedures that are appropriate 

to the site-specific conditions of the project. Section 146.86(b)(3) requires that the long-string 

casing extend to the injection zone and be cemented by circulating cement to the surface in one 

or more stages. It does not, however, specify how cementing would 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, subject to the 

approval of the Director. EPA notes that there are many potential ways to meet the requirement, 

such as the use of staged cementing. 

EPA believes that current cementing technology can address deep well cement columns or lowpressure bottom-of-hole formations. The oil and gas industry has experience drilling and 

cementing wells in very deep formations and in formations with low pressures. Less dense, 

lighter weight cement slurries that include nitrogen foam or lightweight microspheres (Sabins 

2002; Kulakofsky et al. 2005) are used to prevent breakdown of the low pressure formation and 

loss of circulation. Another way to approach low formation pressure conditions is with reverse 

cementing (pumping the cement into the annulus and returning it through the casing). This 

method uses gravity to place the cement and bypass lost circulation zones. Reverse cementing 

can be combined with other methods such as foam cement. Ten successful reverse-cemented 

wells have been completed in a variety of onshore/offshore environments (Chase 2008). 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

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

Letter ID: 0122 Comment ID: 24786 Letter Lines: 742 to 749 

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

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment) 

Comment: (5) Cement and cement additives must be compatible with the CO2 stream and 

formation fluids and of sufficient quality and quantity to maintain integrity 

over the design life of the WELL geologic sequestration project. The 

integrity and location of the cement shall be verified using technology capable 

of evaluating cement quality radially and identifying the location of channels 

to ensure that USDWs are not endangered. 

{See comment above.} 

Individual Response: EPA disagrees that the casing, cement or other materials should only be 

designed for the period of the injection process, rather than the life of the sequestration project. 

GS projects are anticipated to have long life spans in comparison to other types of deep injection 

37
wells. Not only must Class VI wells be able to function safely and properly over the lifespan of 

the GS project, but they must be constructed such that USDWs remain protected after well 

plugging. The requirements at §146.86 will ensure that the well can maintain integrity 

throughout the proposed life span of the project, including after the injection well is plugged and 

through post-injection site care period and beyond. While the risk profile of a GS site will 

decrease following cessation of injection, EPA believes that Class VI wells must be designed to 

protect USDWs from endangerment for the life of the project. Furthermore, rigorous casing and 

cementing help ensure that the Class VI well will not serve as a conduit for movement of fluids 

associated with future injection operations. 

Letter ID: 0122 Comment ID: 24787 Letter Lines: 759 to 768 

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

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment) 

Comment: (i) Depth of setting; 

(ii) Characteristics of the CO2 stream (chemical content, corrosiveness, 

temperature, and density); 

(iii) Injection pressure; 

(iv) Annular pressure; 

(v) Injection rate (intermittent or continuous) and volume of the CO2 stream; 

(vi) Size of casing; and 

(vii) Tubing tensile, burst, and collapse strengths. 

{Repetitive - See application requirements} 

Individual Response: EPA acknowledges that some of the information required under 

§146.86(c)(3) is also required under §146.82(a)(7) as part of the proposed operating 

requirements. However, EPA notes that the Director needs to consider all of the data required 

under §146.86(c) in order to properly determine the tubing and packer specifications, and 

believes this information should be provided together. 

Letter ID: 0122 Comment ID: 24788 Letter Lines: 820 to 821 

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

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

Comment: (c) The owner or operator must record the fluid temperature, pH, conductivity, 

reservoir pressure and the static fluid level of the injection zone(s). 

Individual Response: The text at §146.87(d) as written requires data on the injection zone and 

confining zone or zones. This is to ensure that, if the Director requires characterization of 

additional containment/confining zones (§146.83(b)), appropriate data are collected. 

38
Letter ID: 0122 Comment ID: 24789 Letter Lines: 823 to 824 

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

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

Comment: (d) At a minimum, the owner or operator must determine or calculate the 

following information concerning the injection and confining zone(s): 

Individual Response: The text at §146.87(d) as written requires data on the injection zone and 

confining zone or zones. This is to ensure that, if the Director requires characterization of 

additional containment/confining zones (§146.83(b)), appropriate data are collected. 

Letter ID: 0122 Comment ID: 24790 Letter Lines: 845 to 850 

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

Comment Code: 4110 2.4.1.1 Injection pressure limitations 

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. 

Individual 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. 

Letter ID: 0122 Comment ID: 24791 Letter Lines: 866 to 879 

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

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

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 

39
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.} 

Individual Response: After evaluating the risks and benefits of down-hole shut-off systems and 

considering additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from 

endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or operators of 

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

discretion to mandate automatic down-hole shut-off devices in onshore situations that may 

warrant their use. The 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 shutoff 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. 

Letter ID: 0122 Comment ID: 24792 Letter Lines: 881 to 886 

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

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

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: 

40
Individual 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. 

Letter ID: 0122 Comment ID: 24793 Letter Lines: 904 to 910 

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

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

comment) 

Comment Code: 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.} 

Individual 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. 

Letter ID: 0122 Comment ID: 24794 Letter Lines: 975 to 977 

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

Comment Code: 4660 2.6.6 Geochemical monitoring 

Comment: (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: 

41
Individual Response: Regarding monitoring locations, section §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 must, however, be 

based on site-specific characteristics and vulnerabilities and described in the Director-approved 

testing and monitoring plan. 

Letter ID: 0122 Comment ID: 24795 Letter Lines: 986 to 992 

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

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

Comment: (e) A demonstration of external mechanical integrity pursuant to §146.89(c) at 

least once per year throughout the duration of INJECTION the geologic 

sequestration project; 

{Demonstration of external mechanical integrity should not be necessary after 

cessation of injection and (relatively immediate) dissipation of pressure near 

the wellbore resulting from injection.} 

Individual Response: In the final rule, EPA has revised the text at §144.90(e) to specify that 

owners or operators must demonstrate internal MI at least once per year until the well is plugged. 

Letter ID: 0122 Comment ID: 24796 Letter Lines: 997 to 1004 

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

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

Comment: (g) Testing and monitoring to track the extent of the carbon dioxide plume and 

the position of the pressure front by either monitoring for pressure changes 

in the first formation overlying the confining zone or using indirect, 

geophysical techniques (e.g., seismic, electrical, gravity, or electromagnetic 

surveys and/or down-hole CO2 detection tools); 

{If there are changes in the first formation overlying the confining 

zone, the carbon dioxide stream has not been confined.} 

Individual Response: The final rule, at §146.90(g), requires owners or operators to perform 

monitoring to track the extent of the CO2 plume and pressure front. The owner or operator must 

use direct methods to monitor for pressure changes in the injection zone. Indirect methods (e.g., 

seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools) 

are required unless the Director determines, based on site-specific geology that such methods are 

not appropriate 

42
EPA believes that pressure monitoring in the injection zone is necessary to track the 

development and movement of the pressure front and CO2 plume. When combined with 

information on temperature, pressure data provide an indication of the phase (e.g., gas, 

supercritical) and distribution of the injected CO2 (73 FR 43515). Monitoring can also identify 

needed remedial actions, provide inputs for AoR reevaluation modeling, evaluate predictions of 

plume movement, and target additional geochemical and surface monitoring needs. 

EPA adds that owners or operators may consider (or the Director may require) performing 

additional pressure monitoring in wells that are above the confining zone (e.g., in the same wells 

used to perform ground water quality monitoring required at §146.90(d)) to provide additional 

verification that no pressure changes are occurring above the confining zone due to CO2 leakage. 

The final rule, at §146.90(d), also requires geochemical monitoring above the confining zone. 

Letter ID: 0122 Comment ID: 24797 Letter Lines: 1006 to 1022 

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

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking 

comment) 

Comment: (h) At the Director's discretion, surface air monitoring and/or soil gas 

monitoring to detect movement of carbon dioxide that could endanger a USDW. (1) 

The testing and monitoring plan must be based on potential vulnerabilities 

within the area of review; (2) The monitoring frequency and spatial distribution 

of surface air monitoring and/or soil gas monitoring must reflect baseline data 

and the monitoring plan must include how the proposed monitoring will yield 

useful information on the area of review delineation and/or compliance with 

standards under 40 CFR 144.12; 

{Any requirement for surface air monitoring and/or soil gas monitoring is not 

warranted. If the purpose is to detect "movement of carbon dioxide that could 

endanger a USDW, it would be too late if carbon dioxide were detected in the air 

or soil. In addition, levels of ambient carbon dioxide are too variable for 

this to be useful. RRC suggests eliminating any potential requirement for 

surface air or soil gas monitoring, because formation monitoring should catch 

whatever condition might reasonably be expected to be caught by surface or soil 

gas monitoring. } 

Individual Response: EPA acknowledges that air and soil gas monitoring to ensure USDW 

protection is not necessary at all GS sites and believes that the decision to use surface monitoring 

and the selection of monitoring methods for the purpose of USDW protection will be sitespecific. 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). 

43
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. 

Letter ID: 0122 Comment ID: 24798 Letter Lines: 1100 to 1104 

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

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

Comment: (1) The owner or operator must submit the post-injection site care and site 

closure plan as a part of the permit application to be approved by the 

Director. 

{Redundant - See 146.82(w).} 

Individual Response: EPA clarifies that the reference to the post-injection site care and site 

closure plan, in the final rule at §146.82(a)(17), requires that the plan be included in the 

attachments to the Class VI permit application. The details of the plan contents are included in 

§146.93, along with other requirements related to post-injection site care and site closure. 

Letter ID: 0122 Comment ID: 24799 Letter Lines: 1109 to 1117 

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

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

Comment: (i) The pressure differential between pre-injection and predicted post-injection 

pressures in the injection zone; (ii) The predicted position of the carbon 

dioxide plume and associated pressure front at site closure as demonstrated in 

the AOR evaluation required under §146.84(b); (iii) A description of postinjection monitoring location, methods, and proposed frequency; and (iv) A 

proposed schedule for submitting post-injection site care monitoring results to 

the Director. 

{This should be referenced in 146.82(w).} 

Individual Response: EPA clarifies that the reference to the post-injection site care and site 

closure plan, in the final rule at §146.82(a)(17), is to require that the plan be included in the 

44
attachments to the Class VI permit application. The details of the plan contents are included in 

§146.93 and are enforceable permit conditions, along with other requirements related to postinjection site care and site closure. 

Letter ID: 0122 Comment ID: 24800 Letter Lines: 1119 to 1122 

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

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

Comment: (3) Upon cessation of injection, THE OWNER OR OPERATOR MUST either 

submit an 

amended post-injection site care and site closure plan or demonstrate to the 

Director through monitoring data and modeling results that no amendment to the 

plan is needed. 

Individual Response: 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. 

Letter ID: 0122 Comment ID: 24801 Letter Lines: 1124 to 1126 

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

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

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

Comment: (4) THE OWNER OR OPERATOR MAY May modify and resubmit the postinjection 

site care and site closure plan for the Director's approval within 30 days of 

such change. 

Individual Response: 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. 

Letter ID: 0122 Comment ID: 24802 Letter Lines: 1128 to 1137 

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

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

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

Comment: (b) THE OWNER OR OPERATOR MUST Must monitor the site following the 

cessation 

of injection to show the position of the carbon dioxide plume and pressure front 

and demonstrate that USDWs are not being endangered. 

45
(1) THE OWNER OR OPERATOR MUST Must continue to conduct monitoring as 

specified in the Director-approved post-injection site care and site closure 

plan for THE PERIOD OF TIME at least 50 years following the cessation of 

injection . At the Director's discretion, the monitoring will continue until 

THE DIRECTOR DETERMINES THAT the geologic sequestration project no longer poses 

an endangerment to USDWs. 

Individual Response: EPA disagrees with the suggested edits. However, EPA agrees with 

commenters that there will be circumstances where it can be demonstrated in less than 50 years 

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

reason, the final GS rule offers owners or operators flexibility regarding the duration of the PISC 

timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe 

during the PISC period based on site-specific data, pursuant to requirements at §146.93(b); or (2) 

affording the Director discretion to allow a Class VI well owner or operator to demonstrate, 

based on substantial data during the permitting process, that an alternative PISC timeframe may 

be appropriate if it ensures non-endangerment of USDWs pursuant to requirements at 

§146.93(c). 

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

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

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

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

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

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

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

impacts. 

Letter ID: 0122 Comment ID: 24803 Letter Lines: 1153 to 1162 

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

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations 

Comment: (3) Prior to authorization for site closure, must submit to the Director a 

demonstration, based on monitoring and other site-specific data, that the 

carbon dioxide plume and pressure front have stabilized and that no 

additional monitoring is needed to assure that the GS project does not pose an 

endangerment to USDWs. 

{The carbon dioxide plume will continue to move with other formation fluids - 

they are never static. The real test should be whether or not the pressure has 

dissipated and the pressure front stabilized to the point that there is no 

threat of endangering USDWs.} 

Individual Response: EPA did not make the suggested change. EPA agrees that a complete 

46
cessation of plume movement may not occur at some sites for long time periods due to density 

differences, natural formation flow gradients and diffusion. EPA clarifies that a complete 

cessation of plume movement is not required, only a demonstration that the plume and pressure 

front no longer pose a risk of endangerment to USDWs. 

EPA acknowledges that many site-specific factors will influence the determination of when the 

CO2 plume and pressure front no longer pose a risk of endangerment to USDWs. It is for this 

reason that EPA believes that individual UIC Directors, in consultation with operators, will be in 

the best position to determine whether additional post-injection site care is needed. EPA expects 

this decision to be made based on relevant site data and in consultation with all potentially 

impacted parties. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

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

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

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

The guidance will be available at 

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

Letter ID: 0122 Comment ID: 24804 Letter Lines: 1164 to 1167 

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

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

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

Comment: (4) If such a demonstration cannot be made after the 50-year period, must 

submit to the Director a plan to continue post-injection site care. 

{See comment above.} 

Individual Response: As described above, the post-injection site care timeframe may be 

reduced by the Director if the owner or operator can demonstrate that the remaining pressure 

front and plume no longer pose a risk of endangerment to USDWs. The non-endangerment 

finding is left to the discretion of the Director, based on site-specific information such as plume 

movement, pressure decay, and the location of potential leakage pathways. As suggested by the 

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

the plume and pressure front no longer pose a risk of endangerment to USDWs, as specified in 

§146.93(b)(2-4). EPA retains this provision in the final GS regulation 

GS rule also offers owners or operators flexibility regarding the duration of the PISC timeframe 

by affording the Director discretion to allow a Class VI well owner or operator to demonstrate, 

based on substantial data during the permitting process, that an alternative PISC timeframe may 

be appropriate if it ensures non-endangerment of USDWs pursuant to requirements at 

§146.93(c). 

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

47
adjust the timeframe for a limited number of GS projects during the permitting process where 

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

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

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

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

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

impacts. 

Letter ID: 0122 Comment ID: 24805 Letter Lines: 1169 to 1173 

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

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

Comment: (c) Notice of intent for site closure. Must notify the Director at least 120 

days before site closure. At this time, if any changes have been made to the 

original post-injection site care and site closure plan, THE OWNER OR OPERATOR 

must also provide the revised plan. At the discretion of the Director, a shorter 

notice period may be allowed. 

Individual Response: 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 discussion of post-injection site care in the preamble to the rule for further 

discussion on EPA's final approach. 

Letter ID: 0122 Comment ID: 24806 Letter Lines: 1175 to 1177 

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

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

Comment: (d) After the Director has authorized site closure, THE OWNER OR OPERATOR 

must 

plug all monitoring wells in a manner which will not allow movement of injection 

or formation fluids that endangers a USDW. 

Individual Response: 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. 

Letter ID: 0122 Comment ID: 24807 Letter Lines: 1179 to 1191 

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

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

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

48
Comment: (e) Once the Director has authorized site closure, THE OWNER OR OPERATOR 

must 

submit a site closure report within 90 days that must thereafter be retained at 

a location designated by the Director. The report must include: 

(1) Documentation of appropriate injection and monitoring well plugging as 

specified in §146.92 and paragraph (c) of this section. Must provide a copy of 

a survey plat which has been submitted to the local zoning authority designated 

by the Director, which indicates the location of the injection well relative to 

permanently surveyed benchmarks. Must also submit a copy of the plat to the 

regional administrator of the appropriate EPA Regional Office; 

{Why is this necessary? The EPA regional office will have access to all records 

at the State. } 

Individual Response: The GS regulation at §146.93(g) requires the owner or operator to record 

a notation on the deed to the facility property or other similar document examined during a title 

search that the land has been used to sequester CO2 at the time of site closure. 

Letter ID: 0122 Comment ID: 24808 Letter Lines: 1200 to 1210 

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

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

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

Comment: (f) THE OWNER OR OPERATOR MUSTMust record a notation on the deed to the 

facility property or any other document that is normally examined during title 

search that will in perpetuity provide any potential purchaser of the property 

the following information: 

(1) The fact that land has been used to sequester carbon dioxide; 

(2) The name of the State agency, local authority, and/or tribe with which the 

survey plat was filed, as well as the address of the Regional EPA Office to 

which it was submitted; and (3) The volume of fluid injected, the injection 

zone or zones into which it was injected, and the period over which 

injection occurred. 

Individual Response: The GS regulation at §146.93(g) requires the owner or operator to record 

a notation that the land has been used to sequester CO2 on the deed to the facility property at the 

time of site closure. 

Letter ID: 0122 Comment ID: 24809 Letter Lines: 1212 to 1216 

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

49
Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

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

Comment: (g) Must retain for three years following site closure, records collected during 

the post-injection site care period. THE OWNER OR OPERATOR MUST Must 

deliver the records to the Director at the conclusion of the retention period, 

and the records must thereafter be retained at a location designated by the 

Director for that purpose. 

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

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

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

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

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

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

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

Letter ID: 0122 Comment ID: 24810 Letter Lines: 1218 to 1226 

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

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

Comment: §146.94 Emergency and remedial response. 

(a) As part of the permit application, THE OWNER OR OPERATOR must provide the 

Director with an emergency and remedial response plan that describes actions to 

be taken to address movement of the injection or formation fluids that may cause 

an endangerment to a USDW during construction, operation, closure and postclosure periods. 

{Redundant - See 146.82(X)} 

Individual Response: 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. 

Letter ID: 0122 Comment ID: 24974 Letter Lines: 1139 to 1151 

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

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

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

Comment: (2) If the owner or operator can demonstrate to the satisfaction of the 

Director before 50 years, based on monitoring and other site-specific data, that 

the GS project no longer poses an endangerment to USDWs, the Director may 

50
approve an amendment to the post-injection site care and site closure plan to 

reduce the frequency of monitoring or may authorize site closure before the end 

of the 50-year period. 

{The period of time an owner or operator is required to conduct post-closure 

care monitoring should be based on the ability of the pressure to cause 

endangerment of USDWs. A 50-year post-closure care monitoring period is 

unprecedented and implies that CO2 presents a greater risk than it does. RRC 

suggests that EPA strike the phrase "for at least 50 years" and make the time 

for continued monitoring be based on site specific data. } 

Individual Response: EPA disagrees that a post-injection site care timeframe of 50 years is 

excessive for most Class VI wells. EPA proposed a default post-injection site care timeframe of 

50 years based on a review of research studies, industry reports, and existing environmental 

programs. This analysis was included in an EPA-prepared background document that is available 

in the federal docket, titled "Computational Modeling of Underground Injection of Carbon 

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

Drinking Water." EPA assessed various default timeframes based on additional review of 

research studies and evaluation of public comments. While numerous commenters suggested that 

EPA shorten the monitoring timeframe, none of the commenters provided sufficient data or other 

evidence to warrant a change in the proposed timeframe. While the 10- or 30-year timeframe 

suggested by some of these commenters may be within the timeframe suggested in some studies, 

EPA believes that the potential risks of endangering USDWs will likely not decline within these 

timeframes and available data, including data submitted by commenters, do not support a 

different default timeframe. However, EPA recognizes that alternative timeframes may be 

appropriate under limited, specific circumstances, which is why EPA is providing the Director 

discretion to approve an alternative post-injection site care timeframe as long as the owner or 

operator can meet the requirements provided at §146.93(c). 

EPA acknowledges there will be circumstances where it can be demonstrated in less than 50 

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

this reason, the GS rule offers owners or operators flexibility regarding the duration of the PISC 

timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe 

during the post-injection period based on site-specific data, pursuant to requirements at 

§146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator to 

demonstrate, during the permitting process based on substantial data, that an alternative PISC 

timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to 

requirements at §146.93(c). 

EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in most cases. The default 50 year post-injection site 

care timeframe represents a reasonable and protective monitoring period based on a review of 

research studies, industry reports, and existing environmental programs, and evaluation of public 

comments. 

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

51
52

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

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

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

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

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

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

impacts.