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.









ATTACHMENT B

Technical Comments of the Texas Carbon Capture and Storage 

Association 

In Response to EPA’s Proposed Rule: Federal Requirements Under 

the Underground Injection Control (UIC) Program for Carbon 

Dioxide (CO2) Geologic Sequestration (GS) Wells; Proposed Rule 

Docket ID No. EPA–HQ–OW–2008–0390 

(73 Fed. Reg. 43,492 (July 25, 2008)) 

Submitted December 23, 2008 

By 

Texas Carbon Capture and Storage Association 

P.O. Box 42022 

Austin, Texas 78704 

Contact: Darrick Eugene 

512.542.8814 

 
12/24/2008 

www.txccsa.org 

Technical Comments to the EPA Proposed Rules 

on 

Geologic Sequestration of CO2 

1. § 146.81 Applicability 

The proposed rule provides that owners or operators of authorized Class I industrial, Class II, or 

Class V experimental CO2 injection projects who seek to “convert” these wells to Class VI wells 

and apply for a Class VI permit may be exempted, at the Director’s discretion, from the proposed 

casing and cementing requirements applicable to Class VI wells. 

EPA Proposed § 146.81(c) This subpart applies to owners and operators of permit or 

rule-authorized Class I industrial, Class II, or Class V experimental carbon dioxide 

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). 

It is helpful that EPA recognizes that entities may wish to convert other classes of wells (such as 

Class II wells used for CO2 enhanced oil recovery projects) into Class VI wells and that 

flexibility is necessary for this conversion process. This flexibility should be maintained in the 

final rules but should be enhanced. In addition, the rules should be expanded to provide further 

detail on the conversion process. It is critical that owners and operators have clear and concise 

rules to rely on when seeking to grandfather their existing wells. This provision should be 

revised to limit the Director’s discretion and address all variances resulting in modifications to 

existing wells. For instance, while the rules waive the Class VI casing and cementing 

requirements for existing wells being converted to Class VI wells, the rules do not address other 

construction or construction-related Class VI well requirements that create variances between 

Class VI and Class I, II and V wells. Those requirements include: 

1. Down hole automatic shut-off valve with wellhead hydraulics; 

2. Annulus liquid level detector; 

3. Wellhead corrosion monitoring equipment; and 

4. Mechanical integrity testing. 

Each of these requirements applicable to Class VI wells would require retrofitting or 

modifications to existing wells and could make conversion of wells impracticable or excessively 

expensive. Rather than requiring existing wells to meet prescriptive rules that may not be 

necessary or applicable, the decision to grandfather an existing well should be based solely on 

the well’s passing a mechanical integrity test without physical well modification and meeting all 

other Class VI permit requirements that may be met without well modification. This change 

could be accomplished by revising proposed § 146.81(c) as follows: 

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

industrial, Class II, or Class V experimental carbon dioxide injection projects who seek to 

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apply for a Class VI geologic sequestration permit for their well or wells. If the Director 

determines that USDWs will not be endangered through the results of mechanical 

integrity testing pursuant to § 146.89 that the well is effective in preventing 

endangerment of USDWs, 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) any 

requirement imposing physical well modifications, subject to meeting all other Class 

VI well requirements.

The TxCCSA also comments on the definition of Geologic Sequestration Project referenced in 

this section. 

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

carbon dioxide stream beneath the lowermost formation containing a USDW. It includes 

the subsurface three-dimensional extent of the carbon dioxide plume, associated pressure 

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

This definition restricts geologic sequestration projects to the lowermost formation containing a 

USDW. Restricting injection formations to the lowermost USDW is not necessary for the 

protection of USDWs and would remove a vast number of viable formations from consideration. 

The drilling industry has shown that it can operate CO2 injection wells in an enhanced oil 

recovery (EOR) context without endangering USDWs that are located below the injection zone. 

There should be no blanket prohibition against injection into any approved geologic zone even if 

above the lowermost USDW. The decision should be site-specific and based on evaluation of 

local geology. We fully support the change proposed by the Texas Railroad Commission in its 

comments. 

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

dioxide stream beneath the lowermost formation containing a USDW, or another 

formation, if the Director determines that injection into the other formation will not 

endanger USDWs. It includes the subsurface three-dimensional extent of the carbon 

dioxide plume, associated pressure front, and displaced brine, as well as the surface area 

above that delineated region. 

2. § 146.82 Required Class VI permit information 

This section of the proposed rule sets forth the information which the owner or operator must 

submit to the Director in order to obtain a Class VI well permit. All of the information specified 

must be part of the permit application. But some data are not necessary in light of other 

provisions of the current proposal, and some are not attainable prior to well drilling (applicants 

will not drill the well until it has been approved, otherwise they risk drilling an unusable well). 

Still other data can only be obtained after injection activities have been initiated. Post drilling 

and post injection data should not be required as part of the application process but instead 

should be considered confirmatory data that may be submitted after they are obtained. In 

general, the proposed rule should be modified to require submission of only those data which are 

needed for consideration of the initial permit application, and only those data that may be 

reasonably obtained prior to commencement of installation and operation of the injection well. 

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EPA Proposed: §146.82 (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; 

So long as the Applicant proposes to inject CO2 below the lowermost USDW, as required by the 

proposed rule, there is no justification to require maps and stratigraphic cross sections for the 

entire extent of those USDWs above the lowermost USDW, although mapping and stratigraphic 

cross sections in the immediate vicinity of the proposed injection locations (e.g. where the 

injection wells will be drilled) should still be required. Data regarding all USDWs in the AoR 

will likely be costly and/or difficult to collect and, except as noted above, the usefulness of those 

data seems questionable. 

Accordingly, TxCCSA suggests that subparagraph (f) should be modified as follows: 

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

of all the lowermost USDWs, all USDWs in the immediate vicinity of the proposed 

injection well(s), 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; 

EPA Proposed : §146.82(l) The results of the formation testing program as required in 

paragraph (j) of this section; 

(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; 

The requirements of subparts (l), (r) and (s) of § 146.82 cannot be met until after the well is 

drilled. For example, subparagraph (l) references (j), formation testing. Clearly formation 

testing is a drilling or post completion operation. Similarly, logging and mechanical integrity 

testing also are drilling or post well completion operations. Because this information will be 

collected post application approval, it should not be required prior to the granting of the Class VI 

permit. 

TxCCSA suggests that EPA modify § 146.82 to eliminate subparts (l), (r) and (s) because those 

data do not belong in and in fact may not be available as part of a permit application. 

3. §146.84 Area of review and corrective action. 

EPA’s proposed rule allows each applicant to define the Area of Review (“AoR”) associated 

with the sequestration project. TxCCSA has no objection to this flexible approach as it allows 

the size and shape of the AoR to reflect the unique geology of each CO2 sequestration project. 

However, under §146.84 (a), to define the AoR, an applicant must use a model capable of 

considering the physical and chemical properties of all phases of the injected carbon dioxide 

stream. TxCCSA is uncertain that there is a model that can satisfy this requirement. 

Accordingly, TxCCSA suggests that the proposed rule be amended as follows: 

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§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, to the extent practicable and to the extent determined to be necessary 

by the Director, accounts for the material physical and chemical properties of all 

critical phases of the injected carbon dioxide stream. 

4. § 146.86 Corrosiveness of the carbon dioxide stream, and formation 

fluids; 

Under the proposed rule, the Director is required to determine and specify casing and cementing 

requirements to ensure that a proposed Class VI well is constructed and completed to prevent the 

movement of fluids into or between USDWs or into any unauthorized zones and to permit 

appropriate testing and monitoring. The proposed rule does not adequately explain or justify the 

information requirements set forth therein. 

EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells.(1)(v) 

Corrosiveness of the carbon dioxide stream, and formation fluids; 

The proposed rule requires an applicant to submit to the Director information on the 

corrosiveness of the carbon dioxide stream, and formation fluids. Neither the proposed rule nor 

the Preamable adequately explains whether the information requested is corrosiveness of the 

combined streams of CO2 and formation fluids, or each independent stream (which seems 

unnecessary). Further, the proposed rule or the Preamble should elaborate on what type of data 

may be acceptable –laboratory data for hypothetical streams, empirical testing, analogous wells? 

Clarification is requested on the aforementioned requirements. 

EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells. (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. 

*

* 

* 

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

formation fluids and of sufficient quality and quantity to maintain integrity over the 

design life of the 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. 

Additional proposed requirements affecting casing and cementing of Class VI wells is set forth 

in §§ 146.86 (b)(3) and (5) as quoted above. The requirement, to cement the casing to the surface 

is unnecessary, expensive and contrary to best practices. Under acceptable best practices, the 

long string casing would not be cemented to the surface so that the pressure between the surface 

casing and long string can be monitored to determine if there is migration between the longstring casing and the surface casing. The cementing requirement proposed above would limit the 

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ability to monitor for migration of injected fluids, in this case CO2, behind the casing. 

Additionally, TxCCSA’s field data indicates that the proposed casing and cementing 

requirements are costly while providing limited, if any benefit. According to our findings, under 

existing Class II UIC rules, a conventional cementing program costs approximately $20,000 per 

well. Under the cementing program proposed for Class VI wells the cost could escalate to 

approximately $193,000 per well a potential $173,000 increase, representing a 10% increase in 

total per well costs.1

 

TxCCSA suggests an alternative that protects USDWs, but at a reasonable cost. Rather than 

require cementing of the long string casing to the surface, the proposed rule should require 

cement and cement additives to be compatible with the carbon dioxide stream and formation 

fluids that cover the injection zone and the confining zone, and then require standard (API, 

ASTM International, or comparable standards) industry cements to a certain distance above the 

confining zone. This would place cements that may require special additives at the point where 

USDWs are most effectively protected from the mixture of carbon dioxide and formation fluids 

that could produce carbonic acid. 

TxCCSA suggests the following revision:

§146.86 (b) Casing and Cementing of Class VI Wells. (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 across the surface injection zone and confining zone

and an authorized distance above the confining zone, submitted by the permittee 

and approved by the Director in one or more stages. 

*

* 

* 

(5) To protect USDWs, Ccement and cement additives must be compatible with the 

carbon dioxide stream and formation fluids and of sufficient quality and quantity to 

maintain integrity over the design operating life of the well geologic sequestration 

project must be used through the injection zone and confining zone. 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. 

5. § 146.87 Logging, sampling, and testing prior to injection well 

operation. 

EPA’s proposed § 146.87 delineates the information a permittee must collect during the drilling 

and construction of a Class VI well, prior to actual injection activities. Although the proposed 

rule generally allows the Director to approve alternative methods that provide equivalent or 

better information, it is not clear that the Director can utilize that regulatory flexibility to waive 

unnecessary, duplicative testing which the proposed rule requires in several subparagraphs. 

 

1

 For a typical well completed under Class II UIC rules, the total costs equals $1,700,000. 

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EPA Proposed § 146.87 (a)(2) Before and upon installation of the surface casing:... 

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

and cemented. 

The requirements in §146.87(a)(2)(ii) to secure and submit specified logs before, upon and after 

surface casing installation is excessive. The proposed rule fails to provide a sufficient 

justification for requiring a cement bond and variable density log before and upon installation of 

the long string casing, and requiring a temperature log after the casing is set and cemented. 

Temperature logs are seldom used in the drilling industry to determine cement characteristics as 

they do not provide useful data regarding the bonding of cement. The rules should be modified 

to allow the permittee to select between the specified logs and any other logging tool approved 

by the Director as follows: 

§146.87(a)(2)(ii) A cement bond and variable density log or other approved tool, and or

a temperature log after the casing is set and cemented. [see § 146.12(d)(2)(i)(B) Criteria 

and Standards applicable to Class I nonhazardous wells: Construction 

Requirements.] 

* 

* 

* 

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

required of and/or approved of by the Director. The Director may waive any log or test 

specified in this subparagraph. 

EPA Proposed §146.87 (a)( (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 

Once again, the proposed rule requires testing that would be of little benefit in protecting 

USDWs, but would impose significant costs on operators. For example, TxCCSA sees no basis 

to run a fracture finder log in every well. Fracture finder logs will only see minor fractures 

within the individual formations. The log does not provide information on whether these minor 

fractures can act as conduits between the injection zone and confining zone. To avoid 

unnecessary data collection and submittal, the rules should allow the applicant to propose and 

justify a logging suite based on the reservoir and geology associated with the particular CO2

project. The Director of course should be allowed to approve, or recommend revisions to the 

proposed suite. This would avoid mandating unneeded testing. TxCCSA suggests the following 

revised rule, incorporating this proposed change: 

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

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

and any other or any suite of logs submitted by the permittee and approved by logs

the Director before the casing is installed requires for considering the given geology 

before the casing is installed; and 

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* 

* 

* 

The proposed rule also requires unnecessary and duplicative logging with respect to the longstring casing.

EPA Proposed §146.87(a)( (3) Before and upon installation of the long string casing: (ii) 

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

cemented. 

TxCCSA suggests that the logging options it recommends with respect to surface casing also 

apply for the long-string casing. Thus, the proposed rule should be revised as follows: 

§146.87(a)(3)(ii) A cement bond and variable density log or other approved tool, and or

a temperature log after the casing is set and cemented. [see § 146.12(d)(2)(ii)(C) Criteria 

and Standards applicable to Class I nonhazardous wells: Construction 

Requirements.] 

EPA Proposed §146.87(b) The owner or operator must take and submit to the Director 

whole cores or sidewall cores of the injection zone and confining 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. 

TxCCSA opposes the requirement to collect cores from more than one (1) well within a CO2

project. As a practical matter, the majority of the important physical and geophysical properties 

of the injection reservoir, including the particular attributes of the confining formations can and 

are required to be evaluated from logs and other scientific, reliable measures. A “whole core”, as 

specified in §146.87(b) is only a very small sample of the attributes of a reservoir and a sidewall 

core, an even smaller sample. The former is very expensive to collect, and the latter often not 

available. Neither is essential given the vast amount of data otherwise required, and multiple 

samples, as proposed by the rule, is not reasonable. The unreasonableness of the whole core, 

sidewall core and extra core sampling is evident upon consideration of the sheer volume of 

physical evidence that this provision alone may produce. For example, in Texas there are over 

5000 existing Class II CO2 injection wells. If a small fraction of these wells are converted to 

Class VI CO2 injection wells following the completion of production activities, there will be a 

large universe of cuttings. Where will the regulatory agency store this magnitude of cuttings? 

This may become a particular problem given the total number of CO2 sequestration projects that 

may be proposed. 

TxCCSA suggests the following: 

§146.87(b) At the specific request of the Director and only where core retrieval is 

possible, tThe owner or operator must take and submit to the Director a whole cores or 

sidewall cores of the injection zone and confining system and formation fluid samples 

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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.

EPA Proposed §146.87(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. 

Subparagraph (d) of §146.87 provides permittees with a generic list of data that is required 

regarding the injection and confining zone. Fracture pressure is specified. Under the 

circumstances, fracture pressure should only be calculated, rather than “determined” as any 

determination based on techniques beyond mathematical calculation will require coring or 

perforation of the casing, potentially decreasing the mechanical integrity of the well and running 

directly counter to the objective of the proposed rules. 

With respect to other generic data EPA seeks regarding the injection and confining zones, the 

proposed rule does not to provide sufficient guidance to the permittee on the scope of data 

required on the formation fluids and reservoir zones. TxCCSA requests clarification and 

specifics both with respect to the nature and type of “physical and chemical characteristics” EPA 

expects a permittee to submit in response to the requirements of 146.87(d) (2) & (3). 

EPA Proposed §146.87(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. 

The agency requires the submission of a proposed logging and testing schedule at least 30 days 

in advance of those proposed activities. Although a logging and testing schedule certainly can be 

designed 30 or more days in advance, the actual date that logging is performed is usually 

available only 24 to 48 hours in advance of actual logging operations. A mandatory 30 day 

notice is simply not practical for logging and testing. 

TxCCSA asks that notice requirements in this subpart be adjusted to take into account the 

practical limitations experienced routinely in field operations. Suggested revised language is set 

forth below. 

§146.87(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 

proposed schedule of such activities to the Director at least 30 days prior to conducting 

the first test and submit notice at least 24 hours in advance of the conduct of any 

actual logging and testing. any changes to the schedule 30 days prior to the next 

scheduled test. 

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6. § 146.88 Injection well operating requirements. 

 

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

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

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

operating injection pressure, unless the Director determines that such requirement might 

harm the integrity of the well. 

EPA’s suggested Mechanical Integrity (“MI”) rule to maintain pressure on the annulus exceeding 

the operating injection pressure will, in most cases, result in an exceedance of the burst pressure 

of the casing. If the operator is required to maintain pressure on the annulus at a rate that is 

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

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

recognize this likelihood and thus allows the Director to waive the requirement. However, the 

rule should not require a questionable practice and then permit its waiver. Rather, the practice 

should only be required if the Director makes a determination that the conduct of the test will 

NOT cause a problem. The suggested revision is encapsulated below: 

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

casing with a non-corrosive fluid approved by the Director. If the Director determines 

that such requirement will not harm the integrity of the well, Tthe owner or operator 

must maintain a positive pressure on the annulus a pressure that exceeds the operating 

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

integrity of the well. 

EPA Proposed §146.88(e) The owner or operator must install and use continuous 

recording devices to monitor: The injection pressure; the rate, volume, and temperature 

of the carbon dioxide stream; and the pressure on the annulus between the tubing and the 

long string casing and annulus fluid volume; and must install and use alarms and 

automatic down-hole shut-off systems, designed to alert the operator and shut-in the well 

when operating parameters such as annulus pressure, injection rate or other parameters 

approved by the Director diverge beyond permitted ranges and/or gradients specified in 

the permit; 

The installation and use of automatic down-hole shut-off systems creates a potential avenue for 

leakage and is unnecessary on land-based onshore systems. Down-hole shut-off systems, more 

commonly used in off-shore operations, serve to shut in the well and prevent reservoir fluids 

from exiting the wellbore. They are used in off-shore operations because of the risk of damage 

to the wellhead from atmospheric or anthropogenic phenomenon, such as a hurricane causing 

extensive platform damage or a ship colliding with a platform. But in an onshore injection 

system, a down-hole shut-off system will not determine or deter leakage of fluids in the wellbore 

and therefore is not effective in protecting USDWs. Also, the likelihood of damage to an 

onshore wellhead is extremely remote. The greater risk in a Class VI onshore operation is that 

the mechanics of the down-hole shut-off system will be compromised or malfunction. Such a 

malfunction would require removal of the tubing and shut-off system equipment, thereby 

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creating a potential unwanted migration path. The use of automatic down-hole shut-off systems 

should be limited to off-shore operations. 

Furthermore, the requirement to continuously monitor the annulus fluid volume is impractical, 

because it does not provide any meaningful data regarding potential problems with the operation 

of the well. Requiring the continuous monitoring of the amount of annulus fluid added during 

operations is more practical and will reveal potential leakage paths. TxCCSA recommends the 

following: 

§146.88(e) The owner or operator must install and use continuous recording devices to 

monitor: The injection pressure; the rate, volume, and temperature of the carbon dioxide 

stream; and the pressure on the annulus between the tubing and the long string casing and 

the volume of annulus fluid added to the annulus volume; and the owner or operator 

must install and use alarms and automatic down-hole shut-off systems, designed to alert 

the operator and shut-in off the well when operating parameters such as annulus pressure, 

injection rate or other parameters approved by the Director diverge beyond permitted 

ranges and/or gradients specified in the permit. If the operation involves off-shore

injection, the owner or operator must install and use alarms and automatic downhole shut-off systems, designed to alert the operator and shut-in the well if the 

wellhead is damaged or when operating parameters such as annulus pressure, 

injection rate or other parameters approved by the Director diverge beyond 

permitted ranges and/or gradients specified in the permit; 

 

(f) If an down-hole automatic shutdown is triggered or a loss of mechanical integrity is 

discovered, the owner of operator must immediately investigate and identify as 

expeditiously as possible the cause of the shutoff. 

* 

* 

* 

7. § 146.89 Mechanical integrity. 

EPA Proposed §146.89(c) At least once per year, the owner or operator must use one of 

the following methods to determine the absence of significant fluid movement under 

paragraph (a)(2) of this section: 

 (3) A casing inspection log, if required by the Director. 

Among the test protocols prescribed by the proposed rule to confirm lack of significant fluid 

movement is a casing inspection log. Although this log is optional, it may be required by the 

Director. Conducting a casing inspection log will require the tubing to be pulled from a well, 

and that in turn substantially increases the possibility of a well control event (that is a loss of 

control over well operation). Accordingly, the technique should only be mandated when other 

testing methodologies are unavailable. TxCCSA suggests the following edit: 

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§146.89(c) At least once per year, the owner or operator must use one of the following 

methods to determine the absence of significant fluid movement under paragraph (a)(2) 

of this section: 

(3) A casing inspection log, if a tracer survey or a temperature or noise log cannot be 

obtained and a casing inspection log is thus required by the Director. 

8. § 146.90 Testing and monitoring requirements. 

EPA Proposed §146.90(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; 

Consistent with our comment regarding proposed § 146.88(e) in Section 5 above, TxCCSA is 

unaware of a methodology to monitor the actual volume of annular fluid in the annulus on a 

continuous basis, and thus seeks agency clarification on this portion of the proposed rule. 

EPA Proposed §146.90(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; 

TxCCSA believes the requirements in EPA proposed §146.90(c) related to corrosion monitoring 

are inapplicable. In the vast majority of cases, the CO2 will be transported to the injection site 

through pipelines, will be dehydrated prior to transportation and therefore when injected it will 

be non-corrosive.2

 In those instances, the test methods described in § 146.90(c)(1) and (c)(2) 

(except of course alternatives approved by the Director) will not provide meaningful information 

regarding the mechanical integrity of down-hole casing, tubing and other equipment because the 

CO2 will simply not be corrosive at the surface. Consequently, to have any relevance such 

requirements should be reserved for situations where water saturated CO2 is being injected. 

 

2

 For evidence on CO2 corrosivity in the absence of free water see Don Duttlinger, Enhanced Recovery Intertwines 

Naturally With CO2 Sequestration, Tech Connections Column, January 2004, American Oil and Gas Reporter, 

available at http://www.pttc.org/aogr_columns_archived/aogrcojan04.htm (From the processing/injection 

standpoint, CO2 is noncorrosive as long as it is dry. Proving that point, Kinder Morgan has hydro-tested the 32-

year-old CRC Pipeline built in 1971 to transport CO2. Only one minor failure occurred. After testing, the line was 

rated for 2,025 psi maximum operating pressure, which established a 200 psi increase over most recent ratings); see 

J. Layne, Results of the Hydrotest of the 30-year old Canyon Reef Carriers CO2 Pipeline, 2003 CO2 Flooding 

Conference, December 11-12, 2003, Midland,Texas (University of Texas of the Permian Basin’s Center for Energy 

and Economic Diversification). 

Page 12 of 16 

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§146.90(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 that contact water saturated carbon dioxide streams 

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. 

The requirements of this subpart are waived when the carbon dioxide stream is 

dehydrated to meet pipeline specifications.

EPA Proposed §146.90(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; 

The scope of this proposed requirement is not clear. Does the EPA proposal require the 

submittal of the actual data, or merely an analysis of the pressure fall-off test? 

EPA Proposed §146.90(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

This section effectively proposes a “catch all” to allow the Director undefined discretion to order 

unlimited and unspecified additional monitoring to improve modeling and ensure compliance. 

Vesting the Director with such additional undefined discretional authority increases the 

regulatory risks of the Class VI permitting process and accordingly increases costs. In the event 

that experience implementing the proposed rule requires some future revisions to include 

additional monitoring requirements, such changes should be proposed and adopted through 

appropriate rulemaking procedures and based on an adequate factual and scientific record. 

However, adopting an open-ended power to require “any” additional monitoring, at this early 

stage, undermines the purpose of providing a defined set of rules that members of the public may 

evaluate prior to making the large investments that will be involved in a Class VI projects. Such 

uncertainty can only tend to increase costs, creating a barrier to capital formation and discourage 

geologic sequestration. Accordingly, TxCCSA would recommend deleting this section: 

§146.90(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.

9. § 146.92 Injection well plugging. 

Page 13 of 16 

Austin 1042121v.1
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www.txccsa.org 

EPA Proposed §146.92 (b) Well Plugging Plan. (5) The type and grade and quantity of 

material to be used in plugging. The material must be compatible with the carbon dioxide 

stream; 

The proposed regulation requires the wellbore to be flushed prior to plugging and thus it is 

unnecessary to use cement “compatible with the carbon dioxide stream”. In the absence of 

water, CO2 is non-corrosive and compatible with conventional cements (see discussion under 

Comment #7). Accordingly, the rule should be revised as follows: 

§146.92 (b) Well Plugging Plan. (5) The type and grade and quantity of material to be 

used in plugging. The material must be compatible with the carbon dioxide stream;

10. § 146.93 Post-injection site care and site closure. 

The proposed rule establishes a 50 year default period for post-injection site care. There is, 

however, no factual or scientific basis for such an extensive period. Under EPA’s Resource 

Conservation and Recovery Act rules, which regulate the disposal of hazardous wastes, post 

closure care is limited to 30 years. Defaulting to an excessively long period will increase costs 

and introduce greater regulatory uncertainty, which will discourage capital formation around 

CO2 sequestration. 

Additionally, even though the proposed rule appears to include a 50 year default post injection 

site care period, in reality, that deadline is illusory as it is not self executing. Under the rules, 

post injection site care must continue indefinitely until the Director authorizes closure. The 

closure approval process could take years, even decades, as the Director has no regulatory 

incentive to act on any post injection site care report. Meanwhile, a permittee may be required to 

continue unnecessary and expensive monitoring and reporting indefinitely. 

Whether the post-injection site care period is site-specific, or 10 to 50 years, TxCCSA suggests 

that the post-injection site care provision be reconfigured to be self-executing and allow for 

closure at the end of that period unless the Director affirmatively acts to extend the post-injection 

site care period. These changes are contained in the suggested text below: 

§ 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. 

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

information: 

(i) The pressure differential between pre-injection and predicted postinjection 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 area of review evaluation 

required under § 146.84(b); 

Page 14 of 16 

Austin 1042121v.1
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www.txccsa.org 

(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. 

(3) Upon cessation of injection, owners or operators of Class VI wells 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 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 shall 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. 

* 

* 

* 

 (3) Prior to authorization for the expiration of the period specified in subpart 

(b)(1), site closure, the owner or operator 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 geologic sequestration project does not pose an endangerment to USDWs. 

(4) If within 180 days after the submittal of the data required under 

subparagraph (3), the Director determines that the geological sequestration project 

may continue to pose an endangerment to USDWs, he shall so notify the owner or 

operator of his determination and the basis therefore, and If such a demonstration 

cannot be made (i.e., if the carbon dioxide plume and pressure front have not stabilized) 

after the 50-year period, the owner or operator must submit to the Director a plan to 

continue post-injection site care. 

(5) If within 180 days after the submittal of the data required under 

subparagraph (3) above the Director fails to determine and to notify the owner or 

operator that the geological sequestration project may continue to pose an 

endangerment to USDWs, site closure shall be deemed authorized by rule

(c) Notice of intent for site closure. 

The owner or operator 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 or site closure is authorized by rule, 

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, or site closure is authorized by rule, 

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. The owner or operator must 

provide a copy of a survey plat which has been submitted to the local zoning authority 

Page 15 of 16 

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designated by the Director. The plat must indicate the location of the injection well 

relative to permanently surveyed benchmarks. The owner or operator must also submit a 

copy of the plat to the Regional Administrator of the appropriate EPA Regional Office; 

(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. 

(f) Each owner or operator of a Class VI injection well 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 Environmental Protection 

Agency 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) The owner or operator must retain for three years following site closure, records 

collected during the post-injection site care period. The owner or operator 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. 

Page 16 of 16 

Austin 1042121v.1
Letter ID: 0223 

Commenter: Darrick Eugene 

Organization: Texas Carbon Capture and Storage Association 

Letter ID: 0223 Comment ID: 23955 Letter Lines: 39 to 57 ; 273 to 301 

Comment Code: 1210 1.1.1 Comments about the proposed rule 

Comment: TxCCSA Perspectives on the EPA's Proposed Rule for Geologic Sequestration 

While the EPA's Proposed Rule represents a significant step in the development 

of Carbon Capture and Storage (CCS) as an emissions reduction strategy, the 

Proposed Rule assumes that sequestration or geologic storage [FN1] is defined as 

injection without simultaneous extraction of hydrocarbons, as in the case 

of enhanced oil recovery (EOR) or enhanced gas recovery (EGR) (e.g., enhanced 

coal bed methane or ECBM). The Proposed Rule focuses on sequestration outside 

the context of commercial product extraction and effectively separates CO2 

injection into two classes: sequestration in saline or other non· hydrocarbon 

related target formations and hydrocarbon related sequestration. In general, 

this focus reveals several concerns reflected in the Proposed Rule that the 

TxCCSA hopes to address, including: 1) the lack of clarification of the injectate 

stream which could lead to the stream being considered a waste; 2) the absence 

of a system for qualifying storage sites; 3) a lack of understanding or the 

number of wellbores required for scaled operations; 4) the attribution of harmful 

characteristics to the concept of buoyancy; 5) the lack of consideration for 

simultaneous storage and hydrocarbon production; 6) the post-injection site care 

timeframe; and 7) multi·state jurisdictional issues. 

1 While the term sequestration and storage may be used interchangeably, we 

prefer the term "storage," as it contemplates recovery of injected CO2 for 

beneficial use. 

2 See Regulatory Determination for Oil and Gas and Geothermal Exploration, 

Development, and Production Wastes; Regulatory Determination, 53 Fed. Reg. 25445 

(July 6, 1988) 

3 See the work of Dr. Steven Bryant, director of the Geologic CO2 Storage Joint 

Industry Project in the Center of Petroleum and Geosystems Engineering at the 

University of Texas. 

4 See 73 Fed. Reg. at 43503. 

5 ~ Id at 43524. 

6 See Intergovernmental Panel on Climate Change, Special Report on Carbon 

Dioxide Capture und Storage, 208 (Bert, Metz, et al. eds., 2005); see also Sally 

M. Benson, Carbon Dioxide Capture and Storage: Research Pathways, Progress and 

Potential, Global Climate & Energy Project Annual Symposium, October 2007, 

available at 

http://pangea.stanford.edulresearctv'bensonlab/presentations/Carbon%20Dioxide%20 

1
CaptureYa20and%20Storage%2OY020ResearchO/020Palhways%20Progress'Y020and%20Potential.pdf. 

7 Chiara Trabucchi and Lindene Patton, Storing Carbon: Optionsfor Liability 

Risk. Management, Financial Responsibility, Daily Environment Report, Bureau 

of National Affairs, pg. 8 (Sept. 3, 2008). 

8 See IPCC 2005 Repon, supra, at 208; see also Benson 

9 See Task Force on Carbon Capture and Geologic Storage, The Interstate Oil and 

Gas Compact Commission, Storage of Carbon Dioxide in Geologic Structures: A Legal 

and Regulatory Guide for States and Provinces (Sept. 25,2007) available at 

http://iogcc.mysbopify.comlcollectionslfrontpagelproductslco2-storage-a 

·Legal·andregulatory-guide-for-states-2008. 

10 See 73 Fed. Reg. at 43510. 

Individual Response: The Agency acknowledges the comment and agrees that GS is a key 

climate change mitigation technology that is part of a portfolio of options that could be deployed 

to reduce CO2 emissions. EPA clarifies that the purpose of the GS regulation is to ensure that GS 

is conducted in a manner that protects USDWs from endangerment and only applies to owners or 

operators of wells injecting CO2 for the purpose of long-term storage. 

Please see the remainder of EPA's responses to this comment and the final rule and preamble for 

further details. 

Letter ID: 0223 Comment ID: 23956 Letter Lines: 59 to 77 ; 276 to 278 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: Point #1: The lack of clarification of the CO2 injectate stream which could leadto 

the stream being considered a waste. We recognize and salute EPA's attempt to 

avoid labeling CO2 injection as waste injection. Nevertheless, by tracking 

closely the Class I rules for the injection of hazardous waste (see Attachment 

A), the Proposed Rule appears to treat CO2 as a waste. It will be difficult for 

geologic storage to move forward on this basis. 

Also, in choosing not to state a composition specification minimum for CO2, the 

EPA opens the door to having the CO2 injectate stream declared a waste. We feel 

that is a serious weakness, compelling a regulatory approach for a worst-case 

injectate composition stream, and providing a basis for additional regulation 

under the Resources Conservation and Recovery Act (RCRA) or the Comprehensive 

Environmental Response, Compensation, and Liability Act (CERCLA). The failure to 

define the composition specification minimum for CO2 contributes to the 

overly protective approach of the EPA to the geologic storage of CO2. The EPA 

should address this concern by specifically excluding injected supercritical CO2 

for geologic storage from regulation under both RCRA and CERCLA similar to what 

has been done for wastes associated with the exploration, development and 

production of crude oil, natural gas and geothermal energy under RCRA [FN2] 

2
2 See Regulatory Determination for Oil and Gas and Geothermal Exploration, 

Development, and Production Wastes; Regulatory Determination, 53 Fed. Reg. 25445 

(July 6, 1988) 

Individual Response: The GS rule does not set generic purity standards for CO2 injectate 

streams (e.g., a percent CO2). The GS rule, however, addresses the quality and quantity of 

impurities by requiring owners or operators to submit information on the source of the CO2 and 

its physical and chemical properties. Specifically, the GS rule requires the owner or operator to 

submit data about the site, including an analysis of the chemical and physical characteristics of 

the CO2 stream, as required at §146.82(a)(7)(iv), and information on the compatibility of the 

CO2 stream with fluids in the injection zone and minerals in both the injection and the confining 

zones and the materials used to construct the well, per §146.82(c)(3). This information can help 

the Director determine the potential for geochemical reactions between the injectate (CO2) and 

the host geologic formations, which could result in the plugging of pore spaces or the dissolution 

of formation minerals. 

EPA recognizes that many CO2 streams may be relatively pure, and research indicates that the 

estimated amounts of impurities in a CO2 stream are likely to be low. However, these estimates 

are based on limited information, and uncertainties remain about the expected concentrations of 

impurities from the various types of CO2 streams. The concentrations of minor and trace 

elements in CO2 streams for GS projects are likely to vary by facility, coal composition, plant 

operating conditions, and pollution removal technologies. 

With respect to RCRA, EPA has decided to initiate a separate proposed rulemaking specifically 

to examine the issue of RCRA applicability to CO2 streams being geologically sequestered, 

including the possible option of a conditional exemption from the RCRA requirements for CO2 

GS in Class VI wells. EPA will consider these comments as part of its development of that 

proposal. The Agency will consider issues particular to RCRA in the context of that separate 

rulemaking, and recommends that the commenter read that proposed rule when it is published. 

The Agency notes that commenters who wish to submit comments on the RCRA proposal will 

need to do so during the comment period for that rule. Finally, EPA also notes that the final GS 

rule, which adds new regulations for Class VI wells under the Safe Drinking Water Act 

(SDWA), is not making any changes to the RCRA regulations. 

Letter ID: 0223 Comment ID: 23957 Letter Lines: 79 to 91 ; 279 to 281 

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

trapping mechanism) 

Comment: Point #2: The absence of a systemfor qualifying geologic storage sites. 

Fundamentally, 

the TxCCSA believes that hydrocarbon related geologic storage is one of the 

important avenues by which the next generation of energy production will move 

forward. CO2 occurs naturally in the subsurface and is no stranger to geologists 

3
who attempt to understand fluid migration and subsurface accumulations. The fact 

that CO2 can be trapped in subsurface formations for geologic times is known and 

accepted; and more of these locations will undoubtedly be found. This brings us 

to another concern with the Proposed Rule involving the absence of a system to 

qualify sites for CO2 injection (i.e. a site permitting framework). We feel this 

it is necessary to rate sites for injection security. There is an evolving [FN3] 

framework which could form the basis for qualifying or rating sites. We 

believe that such a framework is necessary for the insurance industry that will 

oversee injection in non-hydrocarbon related geologic storage applications. 

3 See the work of Dr. Steven Bryant, director of the Geologic CO2 Storage Joint 

Industry Project in the Center of Petroleum and Geosystems Engineering at the 

University of Texas. 

Individual Response: EPA disagrees that a single process or framework for evaluating all GS 

sites or formations is appropriate. Instead, the GS rule focuses on evaluating the suitability of 

each site based on site-specific geological and operational data. EPA believes that requiring 

appropriate, site-specific, site characterization by the owner or operator (under §146.82) and 

providing an appropriate degree of flexibility to the Director to evaluate site-specific geologic 

data will afford the greatest protection of USDWs from endangerment. EPA believes that it is 

important for the Director to have as much site-specific information as possible in order to make 

an informed decision to permit injection for GS at a specific site. This approach allows the 

permit writer to establish requirements considering varying site conditions eliminating the need 

for tiered requirements. GS in areas that may pose risks to USDWs, as assessed and identified by 

the owner or operator and the Director during the site selection process, would not be permitted. 

Letter ID: 0223 Comment ID: 23958 Letter Lines: 93 to 102 

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: As currently written, EPA creates a separate Class VI category of UIC regulation 

for CO2 storage in their attempt to avoid the Class I waste moniker. Where CO2 

storage sites can meet the qualifications for permitting, the TxCCSA believes 

that geologic storage is substantially similar to EOR/EGR and in those instances 

any regulations for Class VI wells should reflect more closely UIC Class II 

standards instead of the more stringent Class I hazardous waste well standards. 

If the geologic storage site doesn't qualify or if the injectate composition is 

such that it is truly a waste stream, then the well requirements should more 

directly reflect the requirements of Class I UIC standards, as with the proposed 

Class VI well category. 

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. 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 

4
primary purpose of EOR, and therefore has developed new Class VI regulations to address these 

unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is 

significantly greater than for EOR operations. Reservoir pressure conditions will also be 

different, with Class VI injection operations involving large volumes of CO2 and likely having 

higher pressures within their storage formations than Class II EOR projects which may lead to 

fluid movement that endangers an USDW. 

Therefore, EPA believes that tailored requirements for Class VI wells are necessary to address 

the unique nature of injecting large volumes of CO2 and to ensure that USDWs are protected 

from endangerment. The GS rule contains tailored requirements for the permitting, geologic site 

characterization, AoR and corrective action, well construction, operation, mechanical integrity 

testing, monitoring, well plugging, post-injection site care, and site closure of GS wells that 

directly address issues unique to the nature of large-scale CO2 injection for GS. 

Letter ID: 0223 Comment ID: 23959 Letter Lines: 104 to 125 ; 282 to 282 

Comment Code: 2143 1.6.2.1 Comments in favor of injection into depleted reservoirs 

Comment: Point #3: The draft rules focus on minimizing the number of wellbore penetrations 

at a geologic storage facility. The Preamble discusses "numerous artificial 

penetrations" related to oil and gas reservoirs.[FN4] The TxCCSA believes this focus 

is misplaced and damaging because it potentially eliminates certain target 

geologic formations and represents an unrealistic approach to geologic storage. 

In the first case, the best target geologic formations, typically producing or 

depleted oil and gas reservoirs, where geologic storage projects will be 

of dramatically lower risk, have numerous wellbore penetrations from previous 

exploration activity. Many of those formations have proven trapping conditions 

for substances lighter than brine and therefore very much like CO2. In addition, 

the previous exploration activity provides the understanding of the subsurface 

to guide geologic storage projects. To eliminate those areas based upon a 

postulated concern of leakage from preexisting wellbores is misplaced. From a 

geologic perspective, it is much easier to fix a leaky wellbore than a leaky 

fault. 

In the second case, this focus demonstrates a lack of understanding of the 

compartmentalization of natural reservoir systems. It will be inconceivable to 

expect a single well or even a single digit set of wells to accomplish geologic 

storage on a project of important size. An array of injection wells will be an 

imperative. Also, in the Cost Analysis section of the Preamble, the suggested 

4 See 73 Fed. Reg. at 43503. 

Individual Response: EPA agrees that depleted oil and gas fields are promising formations for 

GS, provided the Class VI siting, AoR and corrective action, well construction and operation, 

monitoring and testing, and post-injection site care and site closure requirements are met under 

5
today’s rulemaking. 

EPA maintains that minimizing the number of artificial penetrations in a formation is imperative 

for preventing endangerment of USDWs. For this reason, the GS rule requires owners or 

operators to conduct an AoR study and address all deficient wells, as specified at §146.84. See 

the discussion of AoR and corrective action in the preamble to the final rule for additional 

information. 

EPA further clarifies that the GS rule is not intended to promote a preference for GS in any 

particular formation type, to address use of resources, or to reduce costs associated with GS into 

various formations. The focus of the GS rule is to ensure that, where GS is deployed, it is 

conducted in a manner that protects USDWs from endangerment. 

Letter ID: 0223 Comment ID: 23960 Letter Lines: 125 to 128 ; 283 to 283 

Comment Code: 6220 3.2.2 Assumptions about the number of monitoring wells (seeking 

comment) 

Comment: imperative. Also, in the Cost Analysis section of the Preamble, the suggested 

use of three monitoring wells per injection well [FN5] displays a theoretical 

approach and a lack of practical understanding in how geologic storage projects 

would be implemented. 

5 ~ Id at 43524. 

Individual Response: EPA recognizes that the number of monitoring wells associated with GS 

projects will be site-specific and vary based on many factors, including the local geologic 

characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 

injected. The proposed rule Cost Analysis described the number of monitoring wells as a ratio to 

the number of injection wells; EPA clarifies that the number of injection wells was based on the 

size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly 

based on the size of the AoR. Because ER project sites have injection wells that are more 

clustered than those in saline formations, the AoR and the number of monitoring wells were 

anticipated to be smaller at an ER project site compared to a saline formation project. EPA 

retained this assumption regarding the density of injection wells for the final rule analysis, but it 

changed its assumption on the number of monitoring wells at each site. For the final rule, the 

Agency assumes one monitoring well above the injection zone per two square miles of AoR; for 

monitoring wells into the injection zone, the Agency assumes one monitoring well per four 

square miles. EPA assumes monitoring wells into the injection zone will also be used to sample 

above the injection zone. The number of monitoring wells assumed for each project type is 

presented in Exhibit 5.2 of the Cost Analysis. 

Because the actual number of monitoring wells that will be necessary for a given project site is 

uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells 

by applying a 25 percent decrease and increase in monitoring wells per project type to the 

6
original assumptions. This change results in annualized incremental rule costs approximately 16 

percent less and 16 percent greater than costs estimated for the primary analysis (as shown in 

Exhibit 5.26 of the Cost Analysis). 

EPA acknowledges that, at this time, it is difficult to know how many monitoring wells will be 

used at GS sites. However, while assumptions are a necessary part of cost modeling, EPA 

disagrees that this approach is "theoretical." The current assumptions in the primary analysis are 

based on information gathered on the DOE pilot projects and EPA's experience with decades of 

injection regulated under the UIC Program. 

For additional information on EPA's final regulatory approach, including testing and monitoring 

requirements, please see the final rule and preamble. 

Letter ID: 0223 Comment ID: 23961 Letter Lines: 130 to 144 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 1616 1.3.1.3 Fluid movement 

Comment: Point #4: The use of the term "CO2 buoyancy," enumerated countless times in the 

draft rules, is misleading. The Preamble to the Proposed Rule makes very clear 

that changes to the VIC program for CO2 geologic storage are based among other 

things on the assertion that CO2 is "buoyant". This is simply incorrect. CO2 is 

a non-explosive, non-flammable, non-toxic gas that possesses different physical 

properties than some other injectates or existing formation fluids. These 

physical properties do not include any special buoyancy characteristics or 

properties. Rather, CO2 is simply more dense than some underground fluids or 

gases and less dense than others. Hence the movement of injected CO2 in a 

reservoir, or any type of system containing different fluids or gases, will vary 

based on the relative densities of the various formation fluids or gases that 

are in the reservoir. The various formation fluids will simply segregate based 

on the relative densities of the fluids or gases, including CO2. As a result, CO2 

may be the fluid that sinks to the bottom, rises to the top, or resides 

somewhere in between the top and the bottom within the reservoir system. 

Individual Response: EPA disagrees with the commenter. Field and laboratory studies that 

evaluated two deep wells exposed to CO2 for nearly three decades have provided evidence of 

upward vertical flow of CO2. In Carey et al (2007), a sample of well cement collected from a 

section of well in the confining zone at SACROC showed evidence of cement alteration 

(carbonation) due to exposure from CO2. (The study was not able to determine whether the 

alteration was due to exposure to CO2 in the presence of water, dry CO2, or to a CO2-brine 

mixture.) In Crow et al (2009), a similar study was conducted on a CO2 production well that was 

drilled into and completed in a natural CO2 producing formation. This study concluded that CO2 

had caused alteration (carbonation) of the well cement and acidification of fluids adjacent to the 

caprock. The study could not determine if the alteration was due to exposure from CO2 diffusion 

up into the overlying caprock or by upward CO2 migration within wellbore system defects 

(perhaps cement-caprock and/or cement-formation interfaces). In both studies, the CO2 

7
apparently moved from the underlying reservoir into the well bore section located within the 

overlying caprock. These observations, especially in conjunction with the larger CO2 volumes 

and higher reservoir pressures anticipated with GS, justify the well construction requirements in 

the final GS rule in order to prevent deterioration of the materials between the well casing and 

the well bore that can result in unacceptable fluid movement. 

EPA adds that buoyancy of CO2 is among several unique considerations for large scale GS that 

warrant the tailored construction requirements at §146.86. For example, seismic surveys at 

Sleipner showed that CO2 had migrated to the top of the 200 to 300 meter thick formation as 

early as 3 years after injection began. The overall behavior of CO2 at Sleipner is for it to migrate 

to the top of the formation and spread laterally from there (Chadwick et al 2006). Additionally, 

CO2 has the potential to be corrosive (in the presence of water or aqueous formation fluids 

during CO2 injection), and the volume of CO2 anticipated to be injected in Class VI wells is 

significantly greater than for Class II ER/ CO2 injection wells. 

Letter ID: 0223 Comment ID: 23962 Letter Lines: 146 to 177 

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: Point #5: The lack of considerationfor simultaneous storage 

and hydrocarbon production. Another concern raised by the proposed EPA rule 

involves the lack of consideration for storage of CO2 during oil and gas 

production. At TxCCSA, we strongly believe that the early CO2 captured from 

industry sources will be injected in substantial volumes and stored during 

existing and new EaR operations. If the capturing company receives no value 

("offset") for reducing emissions, the capture project will not proceed. 

The only reference to the use of EOR sites for storage is contained in proposed 

rule § 146.83(c) which discusses how existing wells, particularly Class II wells 

used for EOR, can be carried over or re-permitted as Class VI wells. The EPA 

should give greater emphasis to the commercial significance of CO2-driven EOR 

under the existing Class 11 well permitting framework. Given the 36+ years of 

experience with CO2 floods in the Permian Basin of West Texas, EOR will serve as 

a bridge to full-scale deployment of geologic storage by facilitating 

infrastructure development. Currently, 3500 miles of pipeline infrastructure 

exist to transport CO2,and CO2-driven EOR's demand for more CO2 is poised to 

increase that number. Furthermore, some estimate that over 8 trillion cubic feet 

of C02 has been stored in the Permian Basin alone. These significant volumes 

represent an already mature industry that should be encouraged to expand. 

The EPA should demonstrate a greater recognition of CO2-driven EOR and 

simultaneously protect underground sources of drinking water by restructuring the 

Proposed Rule, reserving the new Class VI for use in permitting wells in certain 

non-hydrocarbon producing target formations and providing a mechanism that 

recognizes owners and operators seeking to engage in hydrocarbon related 

8
geologic storage under Class II well permits. This mechanism could take the form 

of a Class II subclass that would overlay Class II permit requirements with 

additional area of review, monitoring, reporting, postinjection site care and 

closure requirements. Such a regulatory regime would also recognize the 

differences between non-hydrocarbon related target formations and both depleted 

and producing oil & gas reservoirs. 

Individual Response: EPA recognizes that the oil and gas industry has decades of experience 

injecting CO2 for the purpose of ER, and that sites used for ER may be suitable for GS and may 

be among the first GS sites. Furthermore, EPA recognizes that some CO2 is sequestered when 

injected for purposes of EOR 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. For example, the volume of CO2 anticipated to be injected for long term storage is 

significantly greater than for ER operations. Reservoir pressure conditions will also be different, 

with Class VI injection operations involving large volumes of CO2 and likely having higher 

pressures within their storage formations than Class II ER projects, which may lead to fluid 

movement that endangers an USDW. 

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. 

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

will assist Directors in determining whether an injection project should be transitioned from 

Class II where the primary purpose is oil and gas production to Class VI where the primary 

purpose is long-term storage of large volumes of CO2. The guidance describes recommended 

methods the Director may use to evaluate changes in risk to USDWs from projects, and how the 

Director may determine whether a project should be regulated within the Class II or Class VI 

UIC program. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. For more information, please 

see the discussion on transition of Class II wells in the preamble to the final GS rule. 

EPA clarifies that the GS rule does not require any facilities to sequester CO2; nor does it create 

an economic incentive to do so. The purpose of the GS regulation is to ensure that, where 

deployed, GS is conducted in a manner that does not endanger USDWs. 

Letter ID: 0223 Comment ID: 23963 Letter Lines: 179 to 226 ; 284 to 301 

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

9
Comment: Point #6: The proposed Post-injection Site Care period is too long based on 

prevailing science and risk profiles. The proposed rule establishes a default 

50-year timeframe for the length of the post-injection site care period. TxCCSA 

strongly objects to the use of a 50-year timeframe for post-injection site care. 

Our objection stems from the relative risks associated with the various phases 

of geologic storage operations, the function of various geologic trapping 

mechanisms, the creation of artificial impediments to financial assurance and 

the sagacity of other regulatory proposals. 

First, we believe as the literature suggests that a 50-year timeframe for postinjection site care is too long and wholly unrelated to the risks associated 

with geologic storage. For well-sited, characterized, operated and managed 

sites, the risks accumulate during the operational phase, and decline as sites 

move from post-injection site care to closure to eventual long-term care. 

Therefore, prevailing scientific opinion expects the risk profile to diminish 

with time.[FN6] As Patton and Trabucchi suggest "the likelihood that the risk of 

some events occurring that result in an unexpected release of carbon djoxide 

more than 10 years after termination of injection will become increasingly 

remote due to geochemistry conditions." [FN7] The geochemistry conditions they 

reference include the four main mechanisms which trap CO2 in well-chosen 

geological formations -- 1) structural trapping - which is addressed in the 

proposed rule and is not necessary to discuss further here; 2) residual trapping 

-where CO2 is trapped by capillary forces in the interstices of the rock 

formation which develops about 10 years after injection; 3) dissolution or 

solubility trapping -where the CO2 dissolves into the brine found in the 

geological formation and sinks because the CO2 saturated brine is heavier than 

non-CO2 saturated brine, taking place between 10 and 100 years after injection; 

and 4) finally mineralization or mineral trapping - which happens when dissolved 

CO2 chemically reacts with the formation rock to produce minerals, a process 

requiring hundreds of years.[FN8] 

Given that the greatest risk occurs during the operational stage of a geologic 

storage project and that residual and dissolution trapping start well in advance 

of 50 years, it is difficult to understand why a 50year timeframe for postinjection site care was chosen. A 50-year post-injection site care timeframe is 

simply unrelated to the relative risks associated with geological storage and 

the function of geologic trapping mechanisms that limit the risk of unexpected 

release of CO2 after the termination of injection activity. 

Furthermore, other respected models suggest a much shorter period. For instance. 

the IOGCC Model Rules and Legislation stipulate a 10-29 year post-injection site 

care period.[FN9] Under the IOGCC Model, the operator of the storage site is the 

responsible party and is required to maintain an operational bond during the 

equivalent of a post-injection site care period and until closure. This 10-29 

year post-injection site care period more easily relates to the relative risks 

10
of geologic storage and the geochemical reactions discussed above. Also, in the 

Preamble, EPA acknowledges that a 30-year post-closure care period is recognized 

as the industry standard for the injection of hazardous waste.[FN10] 

6 See Intergovernmental Panel on Climate Change, Special Report on Carbon 

Dioxide Capture und Storage, 208 (Bert, Metz, et al. eds., 2005); see also Sally 

M. Benson, Carbon Dioxide Capture and Storage: Research Pathways, Progress and 

Potential, Global Climate & Energy Project Annual Symposium, October 2007, 

available at 

http://pangea.stanford.edulresearctv'bensonlab/presentations/Carbon%20Dioxide%20 

CaptureYa20and%20Storage%2OY020ResearchO/020Palhways%20Progress'Y020and%20Potential.pdf. 

7 Chiara Trabucchi and Lindene Patton, Storing Carbon: Optionsfor Liability 

Risk. Management, Financial Responsibility, Daily Environment Report, Bureau 

of National Affairs, pg. 8 (Sept. 3, 2008). 

8 See IPCC 2005 Repon, supra, at 208; see also Benson 

9 See Task Force on Carbon Capture and Geologic Storage, The Interstate Oil and 

Gas Compact Commission, Storage of Carbon Dioxide in Geologic Structures: A Legal 

and Regulatory Guide for States and Provinces (Sept. 25,2007) available at 

http://iogcc.mysbopify.comlcollectionslfrontpagelproductslco2-storage-a 

·Legal·andregulatory-guide-for-states-2008. 

10 See 73 Fed. Reg. at 43510. 

Individual Response: EPA agrees that some owners or operators will be able to demonstrate, in 

less than 50 years, that the pressure front and plume no longer pose a risk of endangerment to 

USDWs. However, based on studies, EPA believes that the 50 year default time frame is 

warranted based on additional review of research studies and reports and evaluation of public 

comments. 

EPA believes that the best way to address all possibilities, while ensuring USDW protection 

from endangerment, is to set a 50 year default post-injection site care timeframe, with flexibility 

to: (1) allow 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) afford 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. 

11
EPA clarifies that, in determining the post-injection site care-timeframe for the proposed 

regulation, EPA reviewed industry reports, existing environmental programs, and initial GS 

research studies. EPA provided a synthesis of pertinent results from GS modeling studies in the 

preamble to the proposed regulation. Further explanation of this analysis was included in an 

EPA-prepared background document that is available in the federal docket, titled 

""Computational Modeling of Underground Injection of Carbon Dioxide for Determination of 

Area-of-Review and Potential Risk to Underground Sources of Drinking Water."" Based on 

review of these studies, modeling results indicate that the CO2 plume stabilization may occur on 

the timeframe of 10-100 years after the cessation of injection. EPA believes that a 50-year 

default post-injection site care timeframe is a reasonable midpoint for most GS projects and 

available data, including data submitted by commenters, do not support a different default 

timeframe, and has retained this in the final regulation. 

To the comment about the cost of post-injection site care, EPA does not agree that post-injection 

site care timeframes longer than 30 years will be prohibitively expensive. In fact, EPA believes 

that post-injection site care monitoring will represent a relatively minor component of total 

project cost, and will provide an essential level of protection from endangerment for USDWs. A 

discussion of the costs attributed to monitoring technologies (used during injection and the postinjection site care timeframes) is available in the Technology and Cost Document for the GS 

rule, which is in the federal docket for this rulemaking. EPA believes that it is logical to make 

use of existing monitoring infrastructure at a GS site in order to ensure USDWs are not 

endangered. 

EPA also recognizes the concerns associated with assuring financial responsibility for the long 

time frames over which post-injection site care will be conducted. However, the Agency believes 

that in order to protect USDWs from endangerment under the SDWA operators must 

demonstrate under §146.85 that financial resources are available to plug the injection well and 

provide post-injection site care at the point in time that the first CO2 is injected. EPA is 

developing guidance on financial responsibility to assist owners or operators in evaluating the 

requirements of §146.85 and to assist Directors in evaluating financial responsibility 

demonstrations. The guidance describes the types of financial mechanisms that operators may 

choose to use when evaluating the financial responsibility requirements for GS wells and it will 

also include a section on how to estimate costs to support accurate financial responsibility 

demonstrations. The guidance will be available at 

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

Letter ID: 0223 Comment ID: 23964 Letter Lines: 228 to 245 

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

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: Finally, when mapped to the requirement for financial assurance, this 50-year 

timeframe requirement raises barriers to obtaining financial assurance for 

prospective projects. Section 146.85 of the Proposed Rule requires the owner or 

operator to maintain financial responsibility for corrective action, injection 

12
well plugging, post-injection site care and site closure. Undoubtedly 

owners/operators will enter the private sector financial assurance market for 

some period in order to meet this requirement. Both an uncertain or 50-year 

post-injection site care timeframe create impediments to financial 

responsibility. We believe that an uncertain or exceedingly long post-injection 

site-care period will discourage the development of private sector products to 

address financial responsibility and discourage geologic storage in general. 

Given the limited risk profile of the post-operational phase of geologic 

storage, the impediments to financial responsibility and insurance caused by an 

uncertain or exceedingly lengthy post-injection site care period and the 

precedent set by other proposals, we think that a 50-year post-injection site 

care period is unsupported by the science, unnecessary to protect USDWs and 

unwarranted by current EOR experience. 

Individual Response: As described above, EPA disagrees that a post-injection site care 

timeframe of 50 years is excessive. 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, 

there are circumstances (e.g., little development of mineral trapping of CO2) under which the 

potential risks of endangering USDWs will likely not decline within these timeframes. EPA 

believes that a 50 year post-injection site care timeframe represents a reasonable and protective 

monitoring period and available data do not support a different timeframe. Furthermore, EPA 

believes that a 50-year default post-injection site care timeframe, as required at §146.93(b)(1), is 

not overly burdensome, does not exaggerate the risks associated with GS, is consistent with other 

environmental programs, and sufficiently protects USDWs from endangerment. 

To the comment expressing concern about financial responsibility, EPA recognizes that there are 

challenges associated with assuring funding for activities that will occur far in the future. 

However, the Agency believes that in order to protect USDWs from endangerment under the 

SDWA operators must demonstrate under §146.85 that financial resources are available to plug 

the injection well and provide post-injection site care at the point in time that the first CO2 is 

injected. EPA is developing guidance on financial responsibility to assist owners or operators in 

evaluating the requirements of §146.85 and to assist Directors in evaluating financial 

responsibility demonstrations. The guidance describes the types of financial mechanisms that 

operators may choose to use when evaluating the financial responsibility requirements for GS 

wells and it will also include a section on how to estimate costs to support accurate financial 

responsibility demonstrations. The guidance will be available at 

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

13
EPA adds that the purpose of the GS rule is not to incentivize the use of GS; rather, the purpose 

of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that protects 

USDWs from endangerment. 

EPA acknowledges the concerns of some 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 regulation includes a provision that the 

Director may, at his/her discretion, shorten the post-injection site care timeframe if the owner or 

operator can demonstrate that the GS project does not pose a risk to USDWs, as specified in 

§146.93(b)(2). Such a demonstration will be site-specific, and based on pressure monitoring and 

USDW impacts. 

EPA disagrees that the requirements for financial responsibility are overly stringent. The goal of 

financial responsibility is to ensure that resources are available to prevent the endangerment of 

USDWs from improper plugging, remediation, and management of wells in the event that the 

owner or operator experiences financial difficulties throughout the life of the project. 

Letter ID: 0223 Comment ID: 23965 Letter Lines: 247 to 254 

Comment Code: 1310 1.1.2.4 Comments on other "out of scope" issues, e.g., pore space 

ownership 

Comment: Point #7: Multi-state jurisdictional issues. Finally, the scale of geologic 

storage projects could raise multi-state jurisdictional issues if the CO2 plume 

and AoR extend beyond and across state boundaries. The proposed rule should 

speak to potential multi-state jurisdictional issues in a manner that avoids 

conflicting state requirements. For instance, one option would allow the well 

head or injection site location to control jurisdiction. This would provide a 

framework for addressing multi-state jurisdiction and give owners/operators some 

certainty regarding tbe approach to this issue. 

Individual Response: EPA acknowledges that CO2 plumes may cross jurisdictional boundaries 

and encourages cooperation and coordination among permitting authorities. The final Class VI 

GS rule, at §146.82(a)(2), requires the owner or operator to identify all State, Tribal, and 

Territorial boundaries within the AoR. Based on this information, the Director must provide 

written notification to all States, Tribes, and Territories to inform them of the permit application 

and ensure that they are involved in any necessary processes; this new requirement was added to 

the final rule at §146.82(b). The Agency encourages transparency in the permitting process and 

anticipates that State-State/State-Tribal communication on GS permitting will facilitate 

information sharing and encourage safe, protective projects. 

EPA clarifies that the Class VI permit would be issued by the permitting authority in the state 

where the wellhead is located. 

14
Letter ID: 0223 Comment ID: 23967 Letter Lines: 331 to 386 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment) 

Comment Code: 3820 2.3.1 Well construction procedures 

Comment: 1. § 146.81 Applicability 

The proposed rule provides that owners or operators of authorized Class I 

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

"convert" these wells to Class VI wells and apply for a Class VI permit may be 

exempted, at the Director’s discretion, from the proposed casing and cementing 

requirements applicable to Class VI wells. 

EPA Proposed § 146.81(c) This subpart applies to owners and operators of 

permit or rule- authorized Class I industrial, Class II, or Class V 

experimental carbon dioxide 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). 

It is helpful that EPA recognizes that entities may wish to convert other 

classes of wells (such as Class II wells used for CO2 enhanced oil recovery 

projects) into Class VI wells and that flexibility is necessary for this 

conversion process. This flexibility should be maintained in the final rules but 

should be enhanced. In addition, the rules should be expanded to provide further 

detail on the conversion process. It is critical that owners and operators have 

clear and concise rules to rely on when seeking to grandfather their existing 

wells. This provision should be revised to limit the Director’s discretion and 

address all variances resulting in modifications to existing wells. For 

instance, while the rules waive the Class VI casing and cementing requirements 

for existing wells being converted to Class VI wells, the rules do not address 

other construction or construction-related Class VI well requirements that 

create variances between Class VI and Class I, II and V wells. Those 

requirements include: 

1. Down hole automatic shut-off valve with wellhead hydraulics; 

2. Annulus liquid level detector; 

3. Wellhead corrosion monitoring equipment; and 

4. Mechanical integrity testing. 

Each of these requirements applicable to Class VI wells would require 

retrofitting or modifications to existing wells and could make conversion of 

wells impracticable or excessively expensive. Rather than requiring existing 

wells to meet prescriptive rules that may not be necessary or applicable, the 

15
decision to grandfather an existing well should be based solely on the well’s 

passing a mechanical integrity test without physical well modification and 

meeting all other Class VI permit requirements that may be met without well 

modification. This change could be accomplished by revising proposed § 146.81(c) 

as follows: 

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

Class I industrial, Class II, or Class V experimental carbon dioxide 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 THROUGH THE RESULTS OF MECHANICAL INTEGRITY TESTING 

PURSUANT TO § 

146.89 THAT THE WELL IS EFFECTIVE IN PREVENTING ENDANGERMENT OF 

USDWS, 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) ANY 

REQUIREMENT IMPOSING PHYSICAL WELL MODIFICATIONS, SUBJECT TO 

MEETING ALL OTHER 

CLASS VI WELL REQUIREMENTS. 

Individual Response: EPA expects that any decision to convert a well for long term storage of 

CO2 be made in the context of all available information about the site and history of injection. 

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 other Class VI requirements (i.e., beyond the construction requirements) will 

not be grandfathered. Following conversion of the project to Class VI, many of the unique 

factors of GS sites (e.g., increased reservoir pressures associated with large volumes of stored 

CO2 and the corrosivity of CO2 in the presence of water) warrant the specific operational, MIT, 

monitoring, reporting, plugging, post-injection site care, and site closure requirements in the final 

GS rule. Therefore, following re-permitting, these projects must be subject to the requirements in 

the final GS rule, including requirements related to down-hole shut-off devices, annulus fluid 

monitoring, corrosion monitoring, and MITs. EPA adds that only requiring a MIT test for wells 

converting from Class I, II, or V would not be sufficient to ensure that the well was adequate to 

properly contain the buoyant and corrosive nature of the CO2 stream. EPA believes that downhole shut-off systems and corrosion monitoring are also necessary to ensure the well maintains 

its integrity. See the discussion of EPA's final regulatory approach in the preamble to the GS rule 

for additional detail on these requirements. 

If, because of its construction, a current Class II well cannot be converted for GS in such a way 

that USDWs are protected from endangerment (i.e., by meeting the monitoring, MIT, and other 

requirements for Class VI wells), conversion will not be allowed. While conversion of suitable 

Class II wells for GS is desirable in many situations, EPA stresses that protection of USDWs 

from endangerment is the primary mission and mandate of the UIC program. 

16
To clarify the point at which the primary purpose of CO2 injection transitions from ER (i.e., a 

Class II well) to long-term storage (i.e., Class VI), the final GS rule at §144.19 contains specific, 

risk-based factors to be considered by the Director in making this determination. Furthermore, 

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

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

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

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

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

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

Letter ID: 0223 Comment ID: 23968 Letter Lines: 388 to 414 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment: The TxCCSA also comments on the definition of Geologic Sequestration Project 

referenced in this section. 

Geologic sequestration project means an injection well or wells used to 

emplace a carbon dioxide stream beneath the lowermost formation 

containing a USDW. It includes the subsurface three-dimensional extent 

of the carbon dioxide plume, associated pressure front, and displaced 

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

This definition restricts geologic sequestration projects to the lowermost 

formation containing a USDW. Restricting injection formations to the lowermost 

USDW is not necessary for the protection of USDWs and would remove a vast number 

of viable formations from consideration. The drilling industry has shown that it 

can operate CO2 injection wells in an enhanced oil recovery (EOR) context 

without endangering USDWs that are located below the injection zone. There 

should be no blanket prohibition against injection into any approved geologic 

zone even if above the lowermost USDW. The decision should be site-specific and 

based on evaluation of local geology. We fully support the change proposed by 

the Texas Railroad Commission in its comments. 

Geologic sequestration project means an injection well or wells used to 

emplace a carbon dioxide stream beneath the lowermost formation 

containing a USDW, OR ANOTHER FORMATION, IF THE DIRECTOR DETERMINES 

THAT 

INJECTION INTO THE OTHER FORMATION WILL NOT ENDANGER USDWS. It includes 

the subsurface three- dimensional extent of the carbon dioxide plume, 

associated pressure front, and displaced brine, as well as the surface 

area above that delineated region. 

17
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. It 

establishes: 1) requirements specifying information that owners or operators must submit, and 

Directors must consider, in consultation with PWSS Directors; 2) procedures for public notice of 

a waiver application and for Director-Regional Administrator communication; 3) the waiver 

issuance process; and, 4) additional requirements that apply to owners or operators of Class VI 

wells granted a waiver of the injection depth requirements to ensure USDW protection above and 

below the injection zone. 

EPA also revised the definition of a geologic sequestration project to account for the new 

requirements to include “wells used for geologic sequestration of carbon dioxide that have been 

granted a waiver of the injection depth requirements pursuant to requirements at §146.95.” 

EPA believes that these requirements will ensure USDW protection while providing flexibility to 

UIC program Directors and owners or operators who undertake CO2 injection for GS. The 

Agency believes this approach: 1) responds to concerns about local and regional geologic storage 

capacity limitations imposed by the proposed injection depth requirements; 2) allows for a more 

site-specific assessment of injection depth for GS projects; 3) accommodates injection into 

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or 

between USDWs when appropriate and where it can be demonstrated that USDWs will be 

protected; and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, 

EPA’s approach to addressing injection depth variability through a waiver process responds to 

concerns about future drinking water resource availability and the need to ensure that high 

quality water remains available in sufficient quantities to supply drinking water needs. For 

additional information on the waiver approach, please see the final rule and preamble, as well as 

EPA's responses to comments on the Notice of Data Availability and Request for Comment. 

Letter ID: 0223 Comment ID: 23969 Letter Lines: 416 to 472 

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: 2. § 146.82 Required Class VI permit information 

This section of the proposed rule sets forth the information which the owner or 

operator must submit to the Director in order to obtain a Class VI well permit. 

All of the information specified must be part of the permit application. But 

some data are not necessary in light of other provisions of the current 

proposal, and some are not attainable prior to well drilling (applicants will 

not drill the well until it has been approved, otherwise they risk drilling an 

unusable well). Still other data can only be obtained after injection activities 

18
have been initiated. Post drilling and post injection data should not be 

required as part of the application process but instead should be considered 

confirmatory data that may be submitted after they are obtained. In general, the 

proposed rule should be modified to require submission of only those data which 

are needed for consideration of the initial permit application, and only those 

data that may be reasonably obtained prior to commencement of installation and 

operation of the injection well. 

EPA Proposed: §146.82 (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; 

So long as the Applicant proposes to inject CO2 below the lowermost USDW, as 

required by the proposed rule, there is no justification to require maps and 

stratigraphic cross sections for the entire extent of those USDWs above the 

lowermost USDW, although mapping and stratigraphic cross sections in the 

immediate vicinity of the proposed injection locations (e.g. where the injection 

wells will be drilled) should still be required. Data regarding all USDWs in the 

AoR will likely be costly and/or difficult to collect and, except as noted 

above, the usefulness of those data seems questionable. 

Accordingly, TxCCSA suggests that subparagraph (f) should be modified as 

follows: 

(f) Maps and stratigraphic cross sections indicating the general 

vertical and lateral limits of all THE LOWERMOST USDWs, ALL USDWS IN 

THE IMMEDIATE VICINITY OF THE PROPOSED INJECTION WELL(S), 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; 

EPA Proposed : §146.82(l) The results of the formation testing program 

as required in paragraph (j) of this section; 

(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; 

The requirements of subparts (l), (r) and (s) of § 146.82 cannot be met until 

after the well is drilled. For example, subparagraph (l) references (j), 

formation testing. Clearly formation testing is a drilling or post completion 

operation. Similarly, logging and mechanical integrity testing also are drilling 

or post well completion operations. Because this information will be collected 

post application approval, it should not be required prior to the granting of 

the Class VI permit. 

TxCCSA suggests that EPA modify § 146.82 to eliminate subparts (l), (r) and (s) 

19
because those data do not belong in and in fact may not be available as part of 

a permit application. 

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

proposed regulation will be available at the time the owner or operator develops their initial 

permit application. In response to comments and based on an evaluation of the proposed 

requirements at §146.82, the Agency revised this subpart so that the final regulation specifies 

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

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

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

EPA believes that this revision of §146.82 addresses commenters' concerns regarding the timing 

of information to be submitted. In addition, section §146.82 in the final rule is similar to the 

permit application requirements for other injection well classes, which could help avoid 

confusion about how to meet the permitting requirements for Class VI wells. The requirements at 

§146.82(c) for information to be submitted before operation of the well is authorized are very 

similar to those for Class I wells, with modifications and additions that address the unique 

challenges and types of data collected for GS wells. 

Additionally, EPA disagrees with the commenter that there is no justification to require maps 

and stratigraphic cross sections for the entire extent of those USDWs above the lowermost 

USDW. EPA believes a thorough understanding of the hydrogeologic conditions of all USDWs 

in the AoR is necessary. EPA clarifies that §146.82(a)(5) requires, as part of the site 

characterization and permit application process, that operators submit maps and cross sections 

indicating the general vertical and lateral limits of all USDWs within the area of review. This 

information will result in information on and a characterization of the number, location and 

depth of USDWs. The Director has the authority to request additional hydrogeologic data or 

other data on USDWs as well. 

Letter ID: 0223 Comment ID: 23970 Letter Lines: 474 to 492 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

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

comment) 

Comment: 3. §146.84 Area of review and corrective action. 

EPA’s proposed rule allows each applicant to define the Area of Review ("AoR") 

associated with the sequestration project. TxCCSA has no objection to this 

flexible approach as it allows the size and shape of the AoR to reflect the 

unique geology of each CO2 sequestration project. However, under §146.84 (a), to 

define the AoR, an applicant must use a model capable of considering the 

physical and chemical properties of all phases of the injected carbon dioxide 

stream. TxCCSA is uncertain that there is a model that can satisfy this 

requirement. Accordingly, TxCCSA suggests that the proposed rule be amended as 

20
follows: 

§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, TO THE EXTENT PRACTICABLE AND TO THE EXTENT 

DETERMINED TO BE NECESSARY BY THE DIRECTOR, accounts for the MATERIAL 

physical and chemical properties of all CRITICAL phases of the 

injected carbon dioxide stream. 

Individual Response: EPA disagrees that available multiphase models cannot consider the 

physical and chemical properties of all phases of the injected CO2 stream. Research, as discussed 

in the preamble to the proposed GS regulation and the associated background document 

"Computational Modeling of Underground Injection of Carbon Dioxide for Determination of 

Area-of-Review and Potential Risk to Underground Sources of Drinking Water" (cited in the 

proposed rule preamble as USEPA, 2008d), substantiates the modeling requirements in the GS 

regulation and indicates that technology has advanced to the point that a CO2 injection project 

can be adequately modeled to support both prediction and tracking the movement of the CO2 

plume and pressure front. EPA believes the Director should have discretion to evaluate each plan 

based on current, state of the art modeling science because there are large numbers and types of 

available models and because advances in the field of geologic modeling continue. 

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: 0223 Comment ID: 23971 Letter Lines: 494 to 514 

Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 

146.86) 

Comment: 4. § 146.86 Corrosiveness of the carbon dioxide stream, and formation fluids; 

Under the proposed rule, the Director is required to determine and specify 

casing and cementing requirements to ensure that a proposed Class VI well is 

constructed and completed to prevent the movement of fluids into or between 

USDWs or into any unauthorized zones and to permit appropriate testing and 

monitoring. The proposed rule does not adequately explain or justify the 

information requirements set forth therein. 

EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells.(1)(v) 

Corrosiveness of the carbon dioxide stream, and formation fluids; 

21
The proposed rule requires an applicant to submit to the 

Director information on the corrosiveness of the carbon dioxide stream, and 

formation fluids. Neither the proposed rule nor the Preamable adequately 

explains whether the information requested is corrosiveness of the combined 

streams of CO2 and formation fluids, or each independent stream (which seems 

unnecessary). Further, the proposed rule or the Preamble should elaborate on 

what type of data may be acceptable --laboratory data for hypothetical streams, 

empirical testing, analogous wells? Clarification is requested on the 

aforementioned requirements. 

Individual Response: The GS rule at §146.86(b)(1) requires that all injection well materials be 

compatible with fluids with which the materials may be expected to come into contact. Further, 

the rule, at §146.82(a)(7), requires owners or operators to submit information on planned 

injection pressures, that the Director will use in evaluating the proposed casing, tubing, and 

packer design. EPA adds that, in determining the suitability of well materials and the design of 

the well, the Director must consider various aspects of the injection project, including injection 

pressure, external pressure, internal pressure and axial loading in §146.86(b)(1)(ii), corrosiveness 

of the CO2 stream, and formation fluids in §146.86(b)(1)(v). 

EPA requires under §146.90 that owners or operators submit proposed testing and monitoring 

plans to the Director at the time of the permit application. The operator will need to demonstrate 

that the monitoring wells will be constructed and operated in a manner that will be sufficiently 

protective of USDWs from endangerment. Monitoring wells will differ from injection wells in 

their intent, casing sizes, and depth, although their casing and cementing will likely be similar. 

Unlike injection wells, monitoring wells will not need to be built to withstand CO2 injection, but, 

nonetheless, will need to be built with materials and a design that ensure integrity of the well 

throughout its planned life so that the well does not serve as a conduit for movement of the CO2 

stream or formation fluids. 

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: 0223 Comment ID: 23972 Letter Lines: 516 to 558 

Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment) 

Comment Code: 6100 3.1 Comments on the cost estimates 

Comment: EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells. (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. 

* 

* 

22
* 

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

dioxide stream and formation fluids and of sufficient quality and 

quantity to maintain integrity over the design life of the 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. 

Additional proposed requirements affecting casing and cementing of Class VI 

wells is set forth in §§ 146.86 (b)(3) and (5) as quoted above. The requirement, 

to cement the casing to the surface is unnecessary, expensive and contrary to 

best practices. Under acceptable best practices, the long string casing would 

not be cemented to the surface so that the pressure between the surface casing 

and long string can be monitored to determine if there is migration between the 

long-string casing and the surface casing. The cementing requirement proposed 

above would limit the ability to monitor for migration of injected fluids, in 

this case CO2, behind the casing. Additionally, TxCCSA’s field data indicates 

that the proposed casing and cementing requirements are costly while providing 

limited, if any benefit. According to our findings, under existing Class II UIC 

rules, a conventional cementing program costs approximately $20,000 per well. 

Under the cementing program proposed for Class VI wells the cost could escalate 

to approximately $193,000 per well a potential $173,000 increase, representing a 

10% increase in total per well costs.[FN1] 

[FN1: For a typical well completed under Class II UIC rules, the total costs 

equals $1,700,000.] 

TxCCSA suggests an alternative that protects USDWs, but at a reasonable cost. 

Rather than require cementing of the long string casing to the surface, the 

proposed rule should require cement and cement additives to be compatible with 

the carbon dioxide stream and formation fluids that cover the injection zone and 

the confining zone, and then require standard (API, ASTM International, or 

comparable standards) industry cements to a certain distance above the confining 

zone. This would place cements that may require special additives at the point 

where USDWs are most effectively protected from the mixture of carbon dioxide 

and formation fluids that could produce carbonic acid. 

Individual Response: EPA acknowledges that the Class VI requirements have associated costs 

beyond baseline costs assumed in the cost analysis for this rule (based on an assumption that 

Class I industrial wells are the baseline). The Agency clarifies that the purpose of the GS 

regulation, promulgated under authority of the SDWA, is to ensure that, where GS is deployed, it 

is conducted in a manner that protects USDWs from endangerment. 

The final cost analysis supporting the GS Rule includes cementing costs of $1.20 per foot lengthinch diameter plus 25% of total cementing costs for use of corrosion-resistant cement. For a 

23
representative deep saline injection well used in the cost analysis, this translates to a total 

cementing cost of $406,500 per injection well, representing an incremental cost of approximately 

305,000 over baseline costs. This unit cost is in line with estimates provided by the commenter 

(actual costs are driven by well-specific characteristics). While the rule requirements necessitate 

these additional costs, the requirements are guided by the necessity to address the unique 

challenges posed by CO2 injection (including large injection volumes, the relative buoyancy of 

CO2, its corrosivity in the presence of water, the potential presence of impurities in captured 

CO2, and its mobility within subsurface geologic formations) as they protect USDWs from 

endangerment. 

Letter ID: 0223 Comment ID: 23973 Letter Lines: 560 to 578 

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: TxCCSA suggests the following revision: 

§146.86 (b) Casing and Cementing of Class VI Wells. (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 

across the surface INJECTION ZONE AND CONFINING ZONE AND AN 

AUTHORIZED DISTANCE ABOVE THE CONFINING ZONE, SUBMITTED BY THE 

PERMITTEE 

AND APPROVED BY THE DIRECTOR in one or more stages. 

* 

* 

* 

(5) TO PROTECT USDWS, CCement and cement additives must be 

compatible with the carbon dioxide stream and formation fluids and of 

sufficient quality and quantity to maintain integrity over the 

design OPERATING life of the WELL geologic sequestration project 

MUST BE USED THROUGH THE INJECTION ZONE AND CONFINING ZONE. 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. 

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 

24
cementing help ensure that the Class VI well will not serve as a conduit for movement of fluids 

associated with future injection operations. EPA believes that the requirements for long-string 

casing are appropriate and offer appropriate flexibility: §146.86(b)(3) requires that the longstring 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. 

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: 0223 Comment ID: 23974 Letter Lines: 580 to 601 

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

Comment: 5. § 146.87 Logging, sampling, and testing prior to injection well operation. 

EPA’s proposed § 146.87 delineates the information a permittee must collect 

during the drilling and construction of a Class VI well, prior to actual 

injection activities. Although the proposed rule generally allows the Director 

to approve alternative methods that provide equivalent or better information, it 

is not clear that the Director can utilize that regulatory flexibility to waive 

unnecessary, duplicative testing which the proposed rule requires in several 

subparagraphs. 

EPA Proposed § 146.87 (a)(2) Before and upon installation of the surface 

casing:... (ii) A cement bond and variable density log, and a 

temperature log after the casing is set and cemented. 

The requirements in §146.87(a)(2)(ii) to secure and submit specified logs 

before, upon and after surface casing installation is excessive. The proposed 

rule fails to provide a sufficient justification for requiring a cement bond and 

variable density log before and upon installation of the long string casing, and 

requiring a temperature log after the casing is set and cemented. Temperature 

logs are seldom used in the drilling industry to determine cement 

characteristics as they do not provide useful data regarding the bonding of 

cement. The rules should be modified to allow the permittee to select between 

Individual Response: EPA disagrees that any tests should be waived. EPA believes that all logs, 

surveys, and tests listed at §146.87 are necessary to verify information about the injection and 

confining zones and ensure that the well is being drilled and cased as approved, and has 

mechanical integrity. This information is needed to demonstrate that the well can be operated 

and tested in a manner that protects USDWs from endangerment. While the tests do provide 

information on some of the same items, each test provides unique pieces of information that 

25
build on each other and allow for interpretations not possible with a single test. Existing 

lithologic and geologic information may lack the details needed for site-specific well design and 

the geology needed to support protection of USDWs from endangerment. 

Letter ID: 0223 Comment ID: 23975 Letter Lines: 601 to 614 

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: cement. The rules should be modified to allow the permittee to select between 

the specified logs and any other logging tool approved by the Director as 

follows: 

§146.87(a)(2)(ii) A cement bond and variable density log OR OTHER 

APPROVED TOOL, and OR a temperature log after the casing is set and 

cemented. [see § 146.12(d)(2)(i)(B) CRITERIA AND STANDARDS APPLICABLE TO 

CLASS I NONHAZARDOUS WELLS: CONSTRUCTION REQUIREMENTS.] 

* 

* 

* 

(5) Any alternative methods that provide equivalent or better 

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

THE DIRECTOR MAY WAIVE ANY LOG OR TEST SPECIFIED IN THIS 

SUBPARAGRAPH. 

Individual Response: Cement bond, variable density, and temperature logs are required by 

§146.87(a)(2) upon installation of the surface casing. EPA disagrees that the surface casing 

logging requirements are excessive. Evaluation of all logs, surveys, and tests listed in the rule 

will provide detailed information on the parts of the well that will penetrate the lowermost 

USDW and provide information on the quality of the cement seal with surrounding formations in 

order to ensure protection of USDWs from endangerment. 

Letter ID: 0223 Comment ID: 23976 Letter Lines: 616 to 643 

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

Comment: EPA Proposed §146.87 (a)( (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 

Once again, the proposed rule requires testing that would be of little benefit 

in protecting USDWs, but would impose significant costs on operators. For 

example, TxCCSA sees no basis to run a fracture finder log in every well. 

26
Fracture finder logs will only see minor fractures within the individual 

formations. The log does not provide information on whether these minor 

fractures can act as conduits between the injection zone and confining zone. To 

avoid unnecessary data collection and submittal, the rules should allow the 

applicant to propose and justify a logging suite based on the reservoir and 

geology associated with the particular CO2 project. The Director of course 

should be allowed to approve, or recommend revisions to the proposed suite. This 

would avoid mandating unneeded testing. TxCCSA suggests the following revised 

rule, incorporating this proposed change: 

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

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

fracture finder logs, and any other OR ANY SUITE OF LOGS SUBMITTED 

BY THE PERMITTEE AND APPROVED BY logs the Director BEFORE THE CASING 

IS INSTALLED requires for CONSIDERING the given geology before 

the casing is installed; and 

* 

* 

* 

Individual Response: EPA believes that a minimum suite of logs and tests is necessary at all 

Class VI wells. All logs, surveys, and tests listed at §146.87(a) are necessary to verify 

information about the injection and confining zones and ensure that the well is being drilled and 

cased as approved and has mechanical integrity. 

EPA notes that owners or operators will describe in their permit applications how they will 

construct and test the well, and will also submit site-specific information about the subsurface 

geology. The Director will evaluate the proposed logging activities along with site-specific 

geologic information to identify geologic data of interest. 

EPA adds that, should alternative methods be shown to provide equivalent or better information 

or if site-specific conditions and risk factors dictate that other logs are necessary, the Director has 

the discretion at §146.87(a)(5) to require further logs and tests if necessary and to approve 

alternative methods that provide equivalent or better information. 

Letter ID: 0223 Comment ID: 23977 Letter Lines: 645 to 659 

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: The proposed rule also requires unnecessary and duplicative logging with respect 

to the long-string casing. 

EPA Proposed §146.87(a)( (3) Before and upon installation of the long 

string casing: (ii) A cement bond and variable density log, and a 

temperature log after the casing is set and cemented. 

27
TxCCSA suggests that the logging options it recommends with respect to surface 

casing also apply for the long-string casing. Thus, the proposed rule should be 

revised as follows: 

§146.87(a)(3)(ii) A cement bond and variable density log OR OTHER 

APPROVED TOOL, and OR a temperature log after the casing is set and cemented. 

[see § 146.12(d)(2)(ii)(C) CRITERIA AND STANDARDS APPLICABLE TO CLASS I 

NONHAZARDOUS WELLS: CONSTRUCTION REQUIREMENTS.] 

Individual Response: EPA disagrees that the requirements for logging of the long-string casing 

at §146.87(a)(3)(ii) are unnecessary. While the tests do provide information on some of the same 

items, the tests provide unique pieces of information which enhance each other and allow for 

interpretations not possible with a single test. For example, a variable density log can detect 

microannuli, fractures, and formation effects. Temperature logs can detect fluid or gas flow 

through channels that cannot be detected by either of the other tests. 

Determining the quality of the cementing of the long-string casing is essential to the protection 

of USDWs from endangerment. EPA adds that should alternative methods be shown to provide 

equivalent or better information, the Director may allow such alternatives under §146.87(a)(5). 

Letter ID: 0223 Comment ID: 23978 Letter Lines: 661 to 686 

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

Comment: EPA Proposed §146.87(b) The owner or operator must take and submit to 

the Director whole cores or sidewall cores of the injection zone and 

confining 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. 

TxCCSA opposes the requirement to collect cores from more than one (1) well 

within a CO2 project. As a practical matter, the majority of the important 

physical and geophysical properties of the injection reservoir, including the 

particular attributes of the confining formations can and are required to be 

evaluated from logs and other scientific, reliable measures. A "whole core", as 

specified in §146.87(b) is only a very small sample of the attributes of a 

reservoir and a sidewall core, an even smaller sample. The former is very 

expensive to collect, and the latter often not available. Neither is essential 

given the vast amount of data otherwise required, and multiple samples, as 

proposed by the rule, is not reasonable. The unreasonableness of the whole core, 

sidewall core and extra core sampling is evident upon consideration of the sheer 

volume of physical evidence that this provision alone may produce. For example, 

in Texas there are over 5000 existing Class II CO2 injection wells. If a small 

28
fraction of these wells are converted to Class VI CO2 injection wells following 

the completion of production activities, there will be a large universe of 

cuttings. Where will the regulatory agency store this magnitude of cuttings? 

This may become a particular problem given the total number of CO2 sequestration 

projects that may be proposed. 

Individual Response: EPA clarifies that §146.87(b) allows information on cores from nearby 

wells to be submitted if the owner or operator can demonstrate that core retrieval is not possible 

and that cores from nearby wells are representative of conditions at the Class VI well. EPA 

clarifies that, at a minimum, reports on cores of injection zones, confining zones, and samples of 

formation fluids must be submitted. Section 146.87(b) gives the Director authority to require the 

owner or operator to core other formations in the borehole if necessary to provide sufficient 

geologic information to verify that the site is suitable for GS. 

EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In 

the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The 

owner or operator must take whole cores or sidewall cores of the injection zone and confining 

system and formation fluid samples from the injection zone(s), and must submit to the Director a 

detailed report prepared by a log analyst that includes: well log analyses (including well logs), 

core analyses, and formation fluid sample information...." 

Letter ID: 0223 Comment ID: 23980 Letter Lines: 688 to 698 

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: TxCCSA suggests the following: 

§146.87(b) AT THE SPECIFIC REQUEST OF THE DIRECTOR AND ONLY WHERE CORE 

RETRIEVAL IS POSSIBLE, TThe owner or operator must take and submit 

to the Director A whole cores or sidewall cores of the injection zone 

and confining 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. 

Individual Response: As described above, EPA clarifies that §146.87(b) allows information on 

cores from nearby wells to be submitted if the owner or operator can demonstrate that core 

retrieval is not possible and that cores from nearby wells are representative of conditions at the 

Class VI well. EPA clarifies that, at a minimum, reports on cores of injection zones, confining 

zones, and samples of formation fluids must be submitted. Section 146.87(b) gives the Director 

authority to require the owner or operator to core other formations in the borehole if necessary to 

provide sufficient geologic information to verify that the site is suitable for GS. 

29
Letter ID: 0223 Comment ID: 23981 Letter Lines: 700 to 722 

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

Comment: EPA Proposed §146.87(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. 

Subparagraph (d) of §146.87 provides permittees with a generic list of data that 

is required regarding the injection and confining zone. Fracture pressure is 

specified. Under the circumstances, fracture pressure should only be calculated, 

rather than "determined" as any determination based on techniques beyond 

mathematical calculation will require coring or perforation of the casing, 

potentially decreasing the mechanical integrity of the well and running directly 

counter to the objective of the proposed rules. 

With respect to other generic data EPA seeks regarding the injection and 

confining zones, the proposed rule does not to provide sufficient guidance to 

the permittee on the scope of data required on the formation fluids and 

reservoir zones. TxCCSA requests clarification and specifics both with respect 

to the nature and type of "physical and chemical characteristics" EPA expects a 

permittee to submit in response to the requirements of 146.87(d) (2) & (3). 

Individual Response: EPA disagrees that the wording at §146.87(d) would lead the owner or 

operator to employ destructive testing methods for determination of fracture pressure. The 

wording "determined or calculated" allows for calculations to be performed based on nondestructive methods. EPA is developing guidance on monitoring and testing that will describe 

recommended tests and procedures to assist owners/operators and Directors in evaluating the 

requirements for pre-operational logging and testing under §146.87, including providing 

information on the physical and chemical characteristics of the injection and confining zones. 

This guidance will be available on EPA’s website at 

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

Letter ID: 0223 Comment ID: 23982 Letter Lines: 724 to 747 

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: EPA Proposed §146.87(f) The owner or operator must provide the Director 

with the opportunity to witness all logging and testing by this subpart. 

30
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. 

The agency requires the submission of a proposed logging and testing schedule at 

least 30 days in advance of those proposed activities. Although a logging and 

testing schedule certainly can be designed 30 or more days in advance, the 

actual date that logging is performed is usually available only 24 to 48 hours 

in advance of actual logging operations. A mandatory 30 day notice is simply not 

practical for logging and testing. 

TxCCSA asks that notice requirements in this subpart be adjusted to take into 

account the practical limitations experienced routinely in field operations. 

Suggested revised language is set forth below. 

§146.87(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 PROPOSED schedule of such activities to 

the Director AT LEAST 30 days prior to conducting the first test and 

submit NOTICE AT LEAST 24 HOURS IN ADVANCE OF THE CONDUCT OF ANY 

ACTUAL 

LOGGING AND TESTING. any changes to the schedule 30 days prior to the 

next scheduled test. 

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

The 30-day notification mirrors the current requirement for logging and testing of new Class I 

wells, as described in §146.66. Acknowledging the developing nature of CO2 GS, EPA believes 

that involvement by the permitting authority in each project will provide much needed field data 

for assurance of USDW protection from endangerment and will help update and refine the 

permitting process. Adequate timing of notification will ensure the Director's ability to be 

involved. 

Letter ID: 0223 Comment ID: 23983 Letter Lines: 749 to 768 

Comment Code: 4100 2.4.1 Injection parameters 

Comment: 6. § 146.88 Injection well operating requirements. 

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

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

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

annulus a pressure that exceeds the operating injection pressure, unless 

the Director determines that such requirement might harm the integrity 

of the well. 

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

31
annulus exceeding the operating injection pressure will, in most cases, result 

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

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

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

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

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

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

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

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

problem. The suggested revision is encapsulated below: 

Individual Response: EPA disagrees that maintaining annulus pressures that exceed the 

injection pressure would cause bursting of the casing. A properly designed well that takes into 

account the geologic and geomechanical properties of the site based on information collected 

under §146.82 and meets the construction requirements at §146.86 would be able to maintain 

integrity if the annulus pressure were reasonably higher than injection pressure. 

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

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

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

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

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

leak. 

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

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

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

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

the integrity of the well or endanger a USDW. 

Letter ID: 0223 Comment ID: 23984 Letter Lines: 768 to 776 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4100 2.4.1 Injection parameters 

Comment: problem. The suggested revision is encapsulated below: 

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

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

Director. IF THE DIRECTOR DETERMINES THAT SUCH REQUIREMENT WILL NOT 

HARM 

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

POSITIVE PRESSURE on the annulus a pressure that exceeds the 

operating injection pressure. ., unless the Director determines that 

such requirement might harm the integrity of the well. 

32
Individual Response: As described above, EPA disagrees that maintaining annulus pressures 

that exceed the injection pressure would cause bursting of the casing. Therefore, EPA disagrees 

with the suggested revision. 

Letter ID: 0223 Comment ID: 23986 Letter Lines: 778 to 830 

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: EPA Proposed §146.88(e) The owner or operator must install and use 

continuous recording devices to monitor: The injection pressure; the 

rate, volume, and temperature of the carbon dioxide stream; and the 

pressure on the annulus between the tubing and the long string casing 

and annulus fluid volume; and must install and use alarms and automatic 

down-hole shut-off systems, designed to alert the operator and shut-in 

the well when operating parameters such as annulus pressure, injection 

rate or other parameters approved by the Director diverge beyond 

permitted ranges and/or gradients specified in the permit; 

The installation and use of automatic down-hole shut-off systems creates a 

potential avenue for leakage and is unnecessary on land-based onshore systems. 

Down-hole shut-off systems, more commonly used in off-shore operations, serve to 

shut in the well and prevent reservoir fluids from exiting the wellbore. They 

are used in off-shore operations because of the risk of damage to the wellhead 

from atmospheric or anthropogenic phenomenon, such as a hurricane causing 

extensive platform damage or a ship colliding with a platform. But in an onshore 

injection system, a down-hole shut-off system will not determine or deter 

leakage of fluids in the wellbore and therefore is not effective in protecting 

USDWs. Also, the likelihood of damage to an onshore wellhead is extremely 

remote. The greater risk in a Class VI onshore operation is that the mechanics 

of the down-hole shut-off system will be compromised or malfunction. Such a 

malfunction would require removal of the tubing and shut-off system equipment, 

thereby creating a potential unwanted migration path. The use of automatic downhole shut-off systems should be limited to off-shore operations. 

Furthermore, the requirement to continuously monitor the annulus fluid volume is 

impractical, because it does not provide any meaningful data regarding potential 

problems with the operation of the well. Requiring the continuous monitoring of 

the amount of annulus fluid added during operations is more practical and will 

reveal potential leakage paths. TxCCSA recommends the following: 

§146.88(e) The owner or operator must install and use continuous 

recording devices to monitor: The injection pressure; the rate, volume, 

and temperature of the carbon dioxide stream; and the pressure on the 

annulus between the tubing and the long string casing and THE VOLUME 

OF annulus fluid added to the annulus VOLUME; and the owner or 

33
operator must install and use alarms and automatic DOWN-HOLE shut-off 

systems, designed to alert the operator and shut-in off the well when 

operating parameters such as annulus pressure, injection rate or other 

parameters approved by the Director diverge beyond permitted ranges 

and/or gradients specified in the permit. IF THE OPERATION INVOLVES 

OFF-SHORE INJECTION, THE OWNER OR OPERATOR MUST INSTALL AND USE 

ALARMS 

AND AUTOMATIC DOWN-HOLE SHUT-OFF SYSTEMS, DESIGNED TO ALERT THE 

OPERATOR 

AND SHUT-IN THE WELL IF THE WELLHEAD IS DAMAGED OR WHEN OPERATING 

PARAMETERS SUCH AS ANNULUS PRESSURE, INJECTION RATE OR OTHER 

PARAMETERS 

APPROVED BY THE DIRECTOR DIVERGE BEYOND PERMITTED RANGES AND/OR 

GRADIENTS SPECIFIED IN THE PERMIT; 

(f) If aN down-hole automatic shutdown is triggered or a loss of 

mechanical integrity is discovered, the owner of operator must 

immediately investigate and identify as expeditiously as possible the 

cause of the shutoff. 

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 GS rule, at §146.88(e)(3), requires the installation of down-hole shut-off devices for Class 

VI wells located in the offshore submerged lands within the jurisdiction of a State UIC program. 

The Agency believes that the unique construction and operational conditions for offshore Class 

VI wells, including isolation from shorelines and the need to construct wells through the water 

column and the subsurface, may delay response time in the event of well difficulties. These 

conditions merit requiring automatic down-hole shut-off devices for offshore wells in the 

submerged lands of a State. 

EPA believes that requiring the installation of automatic surface shut-off devices for onshore 

wells (and affording Director's discretion to require down-hole devices where necessary) and 

automatic down-hole shut-off devices for offshore wells in submerged lands within the 

jurisdiction of a State ensures that proper precautions are taken to prevent subsurface fluid 

movement and ensure protection of USDWs. 

Regarding annulus fluid volume, EPA believes that knowing annulus fluid volume, as required at 

§146.88(e), is a necessary component of monitoring well mechanical integrity, but believes that 

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

monitoring of the pressure on the annulus. The final GS rule at §146.90 (b) requires that owners 

34
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: 0223 Comment ID: 23987 Letter Lines: 835 to 855 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4500 2.5 Proposed Mechanical Integrity Testing (MIT) Requirements (40 CFR 

146.89) 

Comment: 7. § 146.89 Mechanical integrity. 

EPA Proposed §146.89(c) At least once per year, the owner or operator 

must use one of the following methods to determine the absence of 

significant fluid movement under paragraph (a)(2) of this section: 

(3) A casing inspection log, if required by the Director. 

Among the test protocols prescribed by the proposed rule to confirm lack of 

significant fluid movement is a casing inspection log. Although this log is 

optional, it may be required by the Director. Conducting a casing inspection log 

will require the tubing to be pulled from a well, and that in turn substantially 

increases the possibility of a well control event (that is a loss of control 

over well operation). Accordingly, the technique should only be mandated when 

other testing methodologies are unavailable. TxCCSA suggests the following edit: 

§146.89(c) At least once per year, the owner or operator must use one of 

the following methods to determine the absence of significant fluid 

movement under paragraph (a)(2) of this section: 

(3) A casing inspection log, if A TRACER SURVEY OR A TEMPERATURE OR 

NOISE LOG CANNOT BE OBTAINED AND A CASING INSPECTION LOG IS THUS 

required by the Director. 

Individual Response: EPA agrees that the casing inspection log is not an appropriate test to 

detect fluid movement behind the casing, but clarifies that it is a technique that can be used to 

determine the presence or absence of corrosion of the long-string casing, and is required if the 

Director determines that it is necessary based on site-specific information. EPA has revised the 

final GS rule to require that the frequency of the casing inspection log be specified in the 

approved testing and monitoring plan at §146.89(d). 

Letter ID: 0223 Comment ID: 23988 Letter Lines: 857 to 868 

Comment Code: 4620 2.6.2 Injectate monitoring 

Comment: 8. § 146.90 Testing and monitoring requirements. 

35
EPA Proposed §146.90(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; 

Consistent with our comment regarding proposed § 146.88(e) in Section 5 above, 

TxCCSA is unaware of a methodology to monitor the actual volume of annular fluid 

in the annulus on a continuous basis, and thus seeks agency clarification on 

this portion of the proposed rule. 

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. 

Letter ID: 0223 Comment ID: 23989 Letter Lines: 870 to 918 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: EPA Proposed §146.90(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; 

TxCCSA believes the requirements in EPA proposed §146.90(c) related to corrosion 

monitoring are inapplicable. In the vast majority of cases, the CO2 will be 

transported to the injection site through pipelines, will be dehydrated prior to 

transportation and therefore when injected it will be non-corrosive.[FN2] In those 

instances, the test methods described in § 146.90(c)(1) and (c)(2) (except of 

course alternatives approved by the Director) will not provide meaningful 

information regarding the mechanical integrity of down-hole casing, tubing and 

other equipment because the CO2 will simply not be corrosive at the surface. 

Consequently, to have any relevance such requirements should be reserved for 

situations where water saturated CO2 is being injected. 

36
[FN2: For evidence on CO2 corrosivity in the absence of free water see Don 

Duttlinger, Enhanced Recovery Intertwines Naturally With CO2 Sequestration, Tech 

Connections Column, January 2004, American Oil and Gas Reporter, available at 

http://www.pttc.org/aogr_columns_archived/aogrcojan04.htm (From the 

processing/injection standpoint, CO2 is noncorrosive as long as it is dry. 

Proving that point, Kinder Morgan has hydro-tested the 32-year-old CRC Pipeline 

built in 1971 to transport CO2. Only one minor failure occurred. After testing, 

the line was rated for 2,025 psi maximum operating pressure, which established a 

200 psi increase over most recent ratings); see J. Layne, Results of the 

Hydrotest of the 30-year old Canyon Reef Carriers CO2 Pipeline, 2003 CO2 

Flooding Conference, December 11-12, 2003, Midland,Texas (University of Texas of 

the Permian Basin’s Center for Energy and Economic Diversification).] 

§146.90(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 

THAT CONTACT WATER SATURATED CARBON DIOXIDE STREAMS 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. 

THE REQUIREMENTS 

OF THIS SUBPART ARE WAIVED WHEN THE CARBON DIOXIDE STREAM IS 

DEHYDRATED 

TO MEET PIPELINE SPECIFICATIONS. 

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. 

EPA disagrees with commenters' assertions that corrosion monitoring is unnecessary or 

excessive. CO2 in the presence of water (including water with NOx, SOx, and H2S impurities) 

can be corrosive to well materials and cements. Thus, although a CO2 stream may be dry, the 

potential for corrosion of well materials down-hole, where the injectate can potentially mix with 

water in the target formation, must be considered. 

Several laboratory studies and a limited number of field studies have investigated and 

characterized the effects of carbonic acid on well materials. Laboratory studies (e.g., Kutchko et 

al., 2007; Kutchko et al., 2008) consistently identify alterations (typically carbonation) of cement 

as the result of interactions between cement and CO2-saturated brine. EPA believes that the 

testing methods specified in the rule are appropriate and have been used successfully by Class I 

37
hazardous waste injection well owners or operators. 

Currently, there are only a few analyses of cement from wells that have been in prolonged 

contact with CO2 in actual field (down-hole) conditions. Evaluation of cement from a well at the 

Scurry Area Canyon Reef Operators Committee (SACROC) site showed alteration, but did not 

show degradation that compromised the structural integrity of the cement (Carey et al., 2007). In 

another study, cement samples were collected and analyzed from a CO2 production well in a 

natural CO2 reservoir in Colorado exposed to a CO2-water down-hole environment for 30 years 

(Crow et al., 2008). The study found evidence of reaction between the CO2-rich water and the 

cement. 

Oil industry research also addresses the effects of corrosion of steel tubing and pipes. Lopez et 

al. (2003) noted that 60 percent of oilfield failures are related to the effects of carbonic acid from 

produced brines on carbon and low alloy steels. 

Laboratory investigation of cement alteration/degradation is an ongoing research area. Few fieldbased studies have been completed to date. The laboratory and field studies currently available 

suggest that corrosion problems can be managed; however, there is not a large enough body of 

research to rule out potential corrosion problems of steel components of injection wells. The 

IPCC (2005) report on carbon dioxide capture and storage reviewed oil and gas industry 

experience with gas injection wells, close industry analogues to CO2 injection wells. The report 

stated that while the design of CO2 injection wells will be very similar to gas injection wells, 

most down-hole components of the CO2 injection wells will “need to be upgraded for higher 

pressure ratings and corrosion resistance.” Given the pressure and corrosion considerations, 

anticipated long lifespan of a GS well and the difficulties that would be associated with a 

corrosion-related well failure, EPA believes that corrosion monitoring in the down-hole 

environment is justified. For these reasons, the final rule requires quarterly corrosion monitoring 

(at §146.90(c)). 

The Agency plans to, every six years, collect and review data on GS projects to determine 

whether the appropriate amount and types of information and appropriate documentation are 

being collected, and to determine if modifications to the requirements are appropriate or 

necessary. 

Letter ID: 0223 Comment ID: 23990 Letter Lines: 920 to 926 

Comment Code: 4640 2.6.4 Pressure fall-off testing (seeking comment) 

Comment: EPA Proposed §146.90(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; 

The scope of this proposed requirement is not clear. Does the EPA proposal 

require the submittal of the actual data, or merely an analysis of the pressure 

fall-off test? 

38
Individual Response: EPA expects that the Director would request an electronic copy of the 

data in addition to an analysis report completed by the owner or operator. This would afford the 

Director the opportunity to review the data and verify that the analysis is accurate. EPA also 

expects that the details of what information must be submitted would be described in the testing 

and monitoring procedures in the Class VI permit. 

Letter ID: 0223 Comment ID: 23991 Letter Lines: 928 to 952 

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 

CFR 146.90) 

Comment: EPA Proposed §146.90(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 

This section effectively proposes a "catch all" to allow the Director undefined 

discretion to order unlimited and unspecified additional monitoring to improve 

modeling and ensure compliance. Vesting the Director with such additional 

undefined discretional authority increases the regulatory risks of the Class VI 

permitting process and accordingly increases costs. In the event that experience 

implementing the proposed rule requires some future revisions to include 

additional monitoring requirements, such changes should be proposed and adopted 

through appropriate rulemaking procedures and based on an adequate factual and 

scientific record. However, adopting an open- ended power to require "any" 

additional monitoring, at this early stage, undermines the purpose of providing 

a defined set of rules that members of the public may evaluate prior to making 

the large investments that will be involved in a Class VI projects. Such 

uncertainty can only tend to increase costs, creating a barrier to capital 

formation and discourage geologic sequestration. Accordingly, TxCCSA would 

recommend deleting this section: 

§146.90(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. 

Individual Response: EPA does not believe that Directors should have undefined discretion 

when ordering additional monitoring requirements. EPA believes that, given the variety of sitespecific circumstances that may be encountered at GS sites, it is reasonable to afford the Director 

discretion only when additional testing and monitoring requirements are added to ensure the 

protection of USDWs. 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 

39
and testing of injection wells, MITs, injection well testing during operation, groundwater quality 

monitoring, tracking the CO2 plume and pressure front, and soil gas and surface air monitoring 

which may be required by the UIC Director for specific GS projects. The guidance will discuss 

how the Director may exercise any discretion. The guidance can be found on EPA’s website at 

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

Letter ID: 0223 Comment ID: 23992 Letter Lines: 954 to 968 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: 9. § 146.92 Injection well plugging. 

EPA Proposed §146.92 (b) Well Plugging Plan. (5) The type and grade and 

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

compatible with the carbon dioxide stream; 

The proposed regulation requires the wellbore to be flushed prior to plugging 

and thus it is unnecessary to use cement "compatible with the carbon dioxide 

stream". In the absence of water, CO2 is non-corrosive and compatible with 

conventional cements (see discussion under Comment #7). Accordingly, the rule 

should be revised as follows: 

§146.92 (b) Well Plugging Plan. (5) The type and grade and quantity of 

material to be used in plugging. The material must be compatible with 

the carbon dioxide stream; 

Individual Response: EPA believes, considering the potentially corrosive nature of CO2 when 

it is in contact with water, that the requirement that the material must be compatible with the 

CO2 stream is appropriate. The final rule retains this requirement because CO2 and water will be 

present in the subsurface. 

Letter ID: 0223 Comment ID: 23993 Letter Lines: 970 to 992 

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: 10. § 146.93 Post-injection site care and site closure. 

The proposed rule establishes a 50 year default period for post-injection site 

care. There is, however, no factual or scientific basis for such an extensive 

period. Under EPA’s Resource Conservation and Recovery Act rules, which regulate 

the disposal of hazardous wastes, post closure care is limited to 30 years. 

Defaulting to an excessively long period will increase costs and introduce 

40
greater regulatory uncertainty, which will discourage capital formation around 

CO2 sequestration. 

Additionally, even though the proposed rule appears to include a 50 year default 

post injection site care period, in reality, that deadline is illusory as it is 

not self executing. Under the rules, post injection site care must continue 

indefinitely until the Director authorizes closure. The closure approval process 

could take years, even decades, as the Director has no regulatory incentive to 

act on any post injection site care report. Meanwhile, a permittee may be 

required to continue unnecessary and expensive monitoring and reporting 

indefinitely. 

Whether the post-injection site care period is site-specific, or 10 to 50 years, 

TxCCSA suggests that the post-injection site care provision be reconfigured to 

be self-executing and allow for closure at the end of that period unless the 

Director affirmatively acts to extend the post-injection site care period. These 

Individual Response: Because of the variety of site-specific circumstances at GS sites, EPA 

believes that individual UIC Directors, in consultation with operators, will be in the best position 

to determine whether additional post-injection site care monitoring is needed (or whether the 

timeframe may be shortened), based on the circumstances of a particular project. EPA expects 

this decision to be made based on relevant site data and in consultation with all potentially 

impacted parties, and will not be made arbitrarily. 

EPA believes that 50 years is an appropriate default post-injection site care timeframe. However, 

EPA recognizes that, in some cases, the post-injection site care timeframe may need to be 

lengthened or shortened based on site-specific circumstances. For instance, if after 50 years, 

monitoring data indicates that the CO2 plume is still moving and may endanger a USDW, 

monitoring should continue on a regular basis. Conversely, if it can be demonstrated in less than 

50 years that the plume and pressure front no longer pose a risk of endangerment to USDWs, 

continuing post-injection site care would be unnecessary (see 146.93(b)(2)). 

EPA disagrees that the 50 year timeframe is unsupported. In determining the post-injection site 

care-timeframe for the proposed regulation, EPA reviewed industry reports, existing 

environmental programs, and initial GS research studies. EPA provided a synthesis of pertinent 

results from GS modeling studies in the preamble to the proposed regulation. Further explanation 

of this analysis was included in an EPA-prepared background document that is available in the 

federal docket, titled "Computational Modeling of Underground Injection of Carbon Dioxide for 

Determination of Area-of-Review and Potential Risk to Underground Sources of Drinking 

Water." Based on review of these studies, modeling results indicate that the CO2 plume 

stabilization may occur on the timeframe of 10-100 years after the cessation of injection. EPA 

believes that a 50-year default post-injection site care timeframe is a reasonable midpoint, and 

has retained this in the final regulation. 

EPA believes that, given the unique challenges associated with GS of large volumes of injected 

CO2, post-injection site care should continue until it can be demonstrated that the CO2 plume 

41
and pressure front no longer pose a risk of endangerment to USDWs. For this reason, the final 

regulation retains the requirement at §146.93(b)(3) that the owner or operator must submit to the 

Director a demonstration, based on monitoring and other site-specific data, that no additional 

monitoring is needed to ensure that the GS project does not pose a risk of endangerment to 

USDWs. Additionally, the permitting authorities responsible for Class VI wells will maintain an 

active role with the owner or operator in order to ensure protection of USDWs from 

endangerment. 

EPA disagrees with the commenter's suggestion regarding self-execution. EPA believes that, 

given the unique challenges associated with GS of large volumes of injected CO2, post-injection 

site care should continue until it can be demonstrated that the CO2 plume and pressure front no 

longer pose a risk of endangerment to USDWs. For this reason, the final regulation retains the 

requirement at 146.93(b)(3) that the owner or operator must submit to the Director a 

demonstration, based on monitoring and other site-specific data, that no additional monitoring is 

needed to ensure that the GS project does not pose a risk of endangerment to USDWs. 

Additionally, the permitting authorities responsible for Class VI wells will maintain an active 

role with the owner or operator in order to ensure protection of USDWs from endangerment. 

Letter ID: 0223 Comment ID: 23994 Letter Lines: 992 to 1093 

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

Comment: Director affirmatively acts to extend the post-injection site care period. These 

changes are contained in the suggested text below: 

§ 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. 

(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 area of review 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 

42
site care monitoring results to the Director. 

(3) Upon cessation of injection, owners or operators of Class VI 

wells 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 modify and resubmit the postinjection site care and site closure plan for the Director’s approval 

within 30 days of such change. 

(b) The owner or operator shall 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. 

* 

* 

* 

(3) Prior to authorization for THE EXPIRATION OF THE PERIOD 

SPECIFIED IN SUBPART (B)(1), site closure, the owner or operator 

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 geologic sequestration project does not pose an 

endangerment to USDWs. 

(4) IF WITHIN 180 DAYS AFTER THE SUBMITTAL OF THE DATA REQUIRED 

UNDER SUBPARAGRAPH (3), THE DIRECTOR DETERMINES THAT THE 

GEOLOGICAL 

SEQUESTRATION PROJECT MAY CONTINUE TO POSE AN ENDANGERMENT TO 

USDWS, HE 

SHALL SO NOTIFY THE OWNER OR OPERATOR OF HIS DETERMINATION AND THE 

BASIS 

THEREFORE, AND If such a demonstration cannot be made (i.e., if the 

carbon dioxide plume and pressure front have not stabilized) after the 

50-year period, the owner or operator must submit to the Director a 

plan to continue post-injection site care. 

(5) IF WITHIN 180 DAYS AFTER THE SUBMITTAL OF THE DATA REQUIRED 

UNDER SUBPARAGRAPH (3) ABOVE THE DIRECTOR FAILS TO DETERMINE AND TO 

NOTIFY THE OWNER OR OPERATOR THAT THE GEOLOGICAL SEQUESTRATION 

PROJECT 

MAY CONTINUE TO POSE AN ENDANGERMENT TO USDWS, SITE CLOSURE SHALL 

BE 

DEEMED AUTHORIZED BY RULE 

(c) Notice of intent for site closure. The owner or operator 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 OR SITE CLOSURE IS 

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AUTHORIZED BY RULE, 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, OR SITE CLOSURE IS 

AUTHORIZED BY RULE, 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. The 

owner or operator must provide a copy of a survey plat which has been 

submitted to the local zoning authority designated by the Director. The 

plat must indicate the location of the injection well relative to 

permanently surveyed benchmarks. The owner or operator must also submit 

a copy of the plat to the Regional Administrator of the appropriate EPA 

Regional Office; 

(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. 

(f) Each owner or operator of a Class VI injection well 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 Environmental Protection Agency 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) The owner or operator must retain for three years following site 

closure, records collected during the post-injection site care period. 

The owner or operator 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: The PISC requirements in the final GS rule, as specified in §146.93(b), 

incorporate a combination of a fixed timeframe and a performance standard approach. EPA 

believes that a default PISC timeframe of 50 years, with Director's discretion to shorten or 

lengthen this timeframe, combined with a site-specific Director’s discretion to create an 

alternative PISC time frame, ensures that USDWs are protected. The GS rule offers owners or 

44
45

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 sitespecific 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 nonendangerment of USDWs pursuant to requirements at §146.93(c). 

EPA expects that the Director would consider the types of information the commenter describes 

in determining whether the plume and pressure front no longer pose a risk of endangerment to 

USDWs and post-injection site care monitoring may be discontinued. 

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

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

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

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

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

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

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

impacts. 

EPA 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 the appropriateness of an alternative post-injection site 

care time frame; demonstrate non endangerment; and perform site closure activities. The 

guidance will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.