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. 

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(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. 

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(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.] 

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(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. 

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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). 

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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. 

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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); 

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(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 

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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. 

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