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 Texa s Carbon Capture and Storage

Association

In Response to EPA’s Proposed Rule: Federal Requirements Under the Underground Injection Cont rol (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestrati on (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 a nd Storage Association

P.O. Box 42022 Austin, Texas 78704 Contact: Darrick Eugene

512.542.881412/24/2008

www.txccsa.org


## Technical Comments to the EPA Proposed Rules

on Geologic Sequestration of CO 2



### 1. § 146.81 Applicability

The proposed rule provides that owners or operator s of authorized Class I industrial, Class II, or Class V experimental CO 2 injection projects who seek to “c onvert” 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 a pplicable 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 Cla ss VI geologic sequestration permit for their well or wells. If the Director determines th at USDWs will not be endangered, such wells are exempt, at the Director’s discretion, fr om 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 CO 2 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. Th is provision should be

revised to limit the Director’s di scretion and address all variances resulting in modifications to existing wells. For instance, while the ru les waive the Class VI casing and cementing requirements for existing wells be ing converted to Clas s VI wells, the rules do not address other

construction or construction-related Class VI we ll requirements that create variances between Class VI and Class I, II and V we lls. 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 c onversion of wells imprac ticable or excessively expensive. Rather than requiri ng existing wells to meet prescr iptive rules that may not be necessary or applicable, the deci sion to grandfather an existing well should be based solely on the well’s passing a mechanical in tegrity test without physical we ll modification and meeting all other Class VI permit requirements that may be met without well modification. This change could be accomplished by revisi ng proposed § 146.81(c) as follows:

(c) This subpart applies to owners and opera tors 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 se questration permit for their well or wells. If the Director

determines that USDWs will not be endange red 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 modificati ons, subject to meeting all other Class VI well requirements.

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

this section.

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

carbon dioxide stream beneath the lowermos t 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 geologi c sequestration projects to the lowermost formation containing a USDW. Restricting injection fo rmations to the lowermost US DW is not necessary for the protection of USDWs and would rem ove a vast number of viable fo rmations from consideration. The drilling industry has shown that it can operate CO 2 injection wells in an enhanced oil recovery (EOR) context without endangering USDWs that are located below the injection zone. There should be no blanket prohibiti on against injection into any a pproved 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 pr oposed by the Texas Railroad Commission in its

comments.

Geologic sequestration project means an inje ction 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 so me 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, othe rwise they risk drilling an unusable well). Still other data can only be obtained after injec tion 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 submissi on 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 in stallation 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 rela tive to the injection zone(s ) and the direction of water
movement, where known;

So long as the Applicant proposes to inject CO 2 below the lowermost USDW, as required by the proposed rule, there is no justif ication to require maps and stra tigraphic cross sections for the

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

cross sections in the immediat e vicinity of the proposed inje ction 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 stratigraph ic cross sections indicating the ge neral vertical and lateral limits

of all the lowermost USDW s
, all USDWs in the immediate vicinity of the proposed injection well(s), water wells and springs within th e area of review, their positions relative to the injec tion zone(s) and the direction of water movement, where known;

EPA Proposed : §146.82(l) The results of the formati on testing program as required in paragraph (j) of this section; (r) All available logging and testing pr ogram data on the well required by§ 146.87; (s) A demonstration of mechanica l 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) referen ces (j), formation testing. Clearly formation testing is a drilling or post completion operation. Similarly, l ogging and mechanical integrity testing also are drilling or pos t well completion operations. Because this information will be collected post applicatio n approval, it should not be required pr ior to the granting of the Class VI permit.

TxCCSA suggests that EPA modify § 146.82 to elimin ate 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 de fine the Area of Review (“AoR”) associated with the sequestration project. TxCCSA has no obj ection to this flexible approach as it allows the size and shape of the AoR to re flect the unique geology of each CO 2 sequestration project. However, under §146.84 (a), to define the AoR, an applicant must us e a model capable of considering the physical a nd 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 pr oposed rule be amended as follows:

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§146.84 Area of review and corrective action

. (a) The area of review is th e region surrounding the geolog ic 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 Dire ctor is required to determine and specify casing and cementing requirements to ensure that a proposed Class VI well is constructed and co mpleted to prevent the

movement of fluids into or between USDWs or into any unaut horized zones and to permit appropriate testing and monitoring. The proposed ru le 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 dioxid e stream, and formation fluids;

The proposed rule requires an applicant to subm it 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 CO 2 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 th e aforementioned requirements.

EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells. (3) At least one long string casing, using a suffic ient number of centralizers, must extend to the injection zone and must be cemented by circulating cemen t to the surface in one or more stages.

*

*

* (5) Cement and cement additives mu st be compatible with th e carbon dioxide stream and formation fluids and of suff icient quality and quan tity to maintain integrity over the design life of the geologic sequestration projec t. The integrity and lo cation 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 acceptab le best practices, the long string casing would not be cem ented to the surface so that th e pressure between the surface casing and long string can be monitored to dete rmine if there is migration between the longstring casing and the surface casing. The cemen ting requirement proposed above would limit the

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ability to monitor for migration of injected fluids, in this case CO 2 , behind the casing. Additionally, TxCCSA’s field data indicate s that the proposed casing and cementing requirements are costly while providing limited, if any benefit. Accordin g to our findings, under existing Class II UIC rules, a conventional cementing program costs approximately $20,000 per well. Under the cementing program proposed fo r 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 th at 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 c onfining zone, and then require standard (API, ASTM International, or comparable standards) industry cements to a cert ain distance above the confining zone. This would pla ce 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 le ast 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

, C 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 operating life of the well geologic s equestration 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 in jection activities

. Although the proposed rule generally allows the Director to approve alternative methods that provide equivalent or better information, it is not clear th at the Director can utilize that regulatory flexibility to waive unnecessary, duplicative testing wh ich 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 installati on of the surface casing:... (ii) A cement bond and variable de nsity log, and a temperature l og 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 installati on is excessive. The proposed rule fails to provide a sufficient justification for requiri ng a cement bond and variable densit y 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 drilli ng industry to determine cement characteristics as they do not provide useful data regarding the bon ding of cement. The ru les should be modified to allow the permittee to select between the speci fied logs and any other logging tool approved by the Director as follows:

§146.87(a)(2)(ii) A cement bond an d 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 equi valent 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 installa tion of the long string casing: (i) Resistivity, spontaneous pot ential, porosity, calip er, gamma ray, fracture finder logs, and any other logs the Direct or requires for the given ge ology before the casing is
installed; and

Once again, the proposed rule re quires testing that would be of little benefit in protecting USDWs, but would impose significant costs on ope rators. 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 inj ection zone and confining zone. To avoid unnecessary data collection and submittal, the ru les should allow the applicant to propose and justify a logging suite based on the reservoir and geology associated w ith the particular CO 2 project. The Director of course should be allowed to approve, or r ecommend revisions to the proposed suite. This would avoid mandating un needed testing. TxCCSA suggests the following revised rule, incorporating this proposed change:

§146.87 (a)( (3) Before and upon installa tion of the long string casing: (i) Resistivity, spontaneous potential, porosit y, 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 insta llation of the long string casing : (ii) A cement bond and variable density log, and a te mperature log after the casing is set and

cemented.

TxCCSA suggests that the logging options it recommends with resp ect to surface casing also apply for the long-string casing. Thus, the pr oposed rule should be revised as follows:

§146.87(a)(3)(ii) A cement bond an d 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 inj ection 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 othe r formations in the borehole.

TxCCSA opposes the requirement to collect cores from more than one (1) well within a CO 2 project. As a practical matter, the majority of the important physical and geophysical properties of the injection reservoir, includ ing 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 re servoir and a sidewall core, an even smaller sample. The former is very expensive to collect, and the latter often not

available. Neither is essentia l given the vast amount of data otherwise required, and multiple samples, as proposed by the rule, is not reasona ble. 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 provis ion alone may produce. For exam ple, in Texas there are over 5000 existing Class II CO 2 injection wells. If a small fraction of these wells are converted to

Class VI CO 2 injection wells following the completion of production activities, there will be a large universe of cuttings. Where will the regula tory agency store this magnitude of cuttings? This may become a particular problem given the total number of CO 2 sequestration projects that may be proposed.

TxCCSA suggests the following:

§146.87(b) At the specific request of the Direct or and only where core retrieval is possible, t T he owner or operator must take and submit to the Director a whole core s or sidewall core s of the injection zone and confini ng 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 retrie val 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 concer ning the injection and confining zone(s): (1) Fracture pressure; (2) Other physical and chemical characteristics of the inje ction 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, potential ly decreasing the mechanical in tegrity of the well and running directly counter to the obj ective 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 gui dance to the permittee on the scope of data required on the formation fluids and reservoi r 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 requireme nts 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 schedul e 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. Althoug h a logging and testing sc hedule certainly can be designed 30 or more days in advance, the actu al 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 practi cal for logging and testing.

TxCCSA asks that notice requireme nts in this subpart be adjust ed to take in to account the practical limitations experienced ro utinely in field operations. Sugge sted 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 subpa rt. 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. an y changes to the schedule 30 days prior to the next

schedul ed 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-co rrosive 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 cas es, result in an exceedance of the burst pressure of the casing. If the operator is required to main tain pressure on the annulus at a rate that is greater than the injec tion pressure (as indicated in EP A proposed §146.88(c)), monitoring the annulus pressure may not be an accurate indicator of mechanical integrity. The EPA appears to recognize this likeli hood 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 a nnulus between the tubing and the long string casing with a non-corrosive flui d approved by the Director. If the Director determines that such requirement will not ha rm the integrity of the well, T t he 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 mu st install and use continuous recording devices to monitor: The injecti on 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 volu me; and must install and use alarms and automatic down-hole shut-off systems, designe d to alert the operator and shut-in the well when operating parameters such as annulus pre ssure, injection rate or other parameters approved by the Director diverge beyond perm itted ranges and/or gradients specified in the permit;

The installation and use of automatic down-hole s hut-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 anthr opogenic 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 US DWs. 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 remova l 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 m onitor the annulus fluid volume is impractical, because it does not provide any meaningful data regarding potential pr oblems with the operation of the well. Requiring the continuous monitori ng of the amount of annulus fluid added during operations is more practical a nd will reveal potential leakag e paths. TxCCSA recommends the following:

§146.88(e) The owner or operator must install and use conti nuous recording devices to monitor: The injection pressure; the rate, volume, and temperature of the carbon dioxide stream; and the pressure on the annulus betw een 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 parame ters such as annulus pressure, injection rate or other parameters approve d 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 in stall and use alarms and automatic downhole shut-off systems, designed to alert the operator and shu t-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 grad ients specified in the permit ;

(f) If a n down

- hole automatic shutdown is triggered or a loss of mechanical integrity is discovered, the owner of operator must i mmediately 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 abs ence 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 conf irm lack of significant fluid movement is a casing inspection log. Although this log is optiona l, 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 possi bility of a well control event (that is a loss of control over well operation). Accordingly, the technique shoul d 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 signi ficant 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 propo sed § 146.88(e) in Sect ion 5 above, TxCCSA is unaware of a methodology to monitor the actual volume of annular flui d in the annulus on a continuous basis, and thus seeks agency clarif ication 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 th at the well components meet the minimum standards for material strength and performan ce set forth in § 146.86(b) by: (1) Placing coupons of the well construction ma terials 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 met hod approved by the Director;

TxCCSA believes the requirements in EPA propos ed §146.90(c) related to corrosion monitoring are inapplicable. In the vast majority of cases, the CO 2 will be transported to the injection site through pipelines, will be dehydrated prior to trans portation and therefore when injected it will

be non-corrosive. 2 In those instances, the test met hods 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-hol e casing, tubing and other equipment because the

CO 2 will simply not be corrosive at the surface. Consequently, to have any relevance such requirements should be reserved for situations where water saturated CO 2 is being injected.

2 For evidence on CO 2 corrosivity in the absence of free water see Don Duttlinger, Enhanced Recovery Intertwines Naturally With CO 2 Sequestration , Tech Connections Column, January 2 004, American Oil and Gas Reporter,

available at http://www.pttc.org/aogr_columns_archived/aogrcojan04.htm (From the processing/injection standpoint, CO 2 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 CO 2 . Only one minor failure occurred. After testing, the line was rated for 2,025 psi maximum operating pressure, which esta blished a 200 psi increase over most recent ratings); see J. Layne, Results of the Hydrotest of the 30-year old Canyon Reef Carriers CO 2 Pipeline , 2003 CO 2 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 ma terials 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 saturate d 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 ma terials 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 me thod approved by the Director. The requirements of this subpart are waiv ed 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 re quired 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 monitori ng, as required by the Director, necessary to support, upgrade, and improve co mputational 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 ch anges should be proposed and adopted through appropriate rulemaking procedures and based on an adequate fact ual and scientific record. However, adopting an open-ended power to requi re “any” additional mon itoring, at this early stage, undermines the purpose of providing a define d 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, crea ting a barrier to capital formation and discourage geologic sequestration. Acco rdingly, TxCCSA would recomme nd 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

u nder § 146.84(b) and to determine comp liance 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) Th e type and grade and quantity of material to be used in plugging. The material must be compatible w ith the carbon dioxide

stream;

The proposed regulation requires the wellbore to be flushed prior to plugging and thus it is unnecessary to use cement “compa tible with the carbon dioxide st ream”. In the absence of
water, CO 2 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 gr ade 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 re gulate the disposal of hazardous wastes, post closure care is limited to 30 years. Defaulting to an excessively long peri od will increase costs and introduce greater regulatory uncertainty, which will discourage capital formation around

CO 2 sequestration.

Additionally, even though the propos ed rule appears to include a 50 year default post injection site care period, in reality, that de adline is illusory as it is not self executing. Under the rules, post injection site care must continue indefinite ly 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 m onitoring and reporting indefinitely.

Whether the post-injection site car e 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 Direct or affirmatively acts to extend the post-injection site care period. These changes are cont ained 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 clos ure that meets the requirements of paragraph (a)(2) of this sect ion 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 appli cation 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 demons trated in the area of review evaluation required under § 146.84(b);

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(iii) A description of post-injectio n monitoring location, methods, and proposed frequency; and (iv) A proposed schedule for subm itting post-injection site care monitoring results to the Director. (3) Upon cessation of injection, owners or ope rators of Class VI wells must either submit an amended post-injection site care an d 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 a nd 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 a nd demonstrate that USDWs are not being endangered.

*

*

* (3) Prior to authorization for the expiration of the peri od specified in subpart (b)(1), site closure , the owner or operator must submit to the Director a demonstration, based on monitoring and other site specifi c 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 th at 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 pl ume and pressure front have not stabilized)

after the 50

- year period, the owner or operator must subm it 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 notif y the Director at least 120 da ys 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 re vised 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 formati on 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 cl osure report within 90 days that must

thereafter be retained at a location designated by the Direct or. The report must include: (1) Documentation of appropriate inj ection and monitoring well plugging as specified in § 146.92 and paragr aph (c) of this section. Th e 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 Administra tor of the appropriate EPA Regional Office; (2) Documentation of appropria te 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 cond itions on subsequent drilling activities that may penetrate the injection and confining zone(s); and (3) Records reflecting the nature, composition and volum e of the carbon dioxide

stream. (f) Each owner or operator of a Class VI inj ection 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 a ny 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 addres s of the Regional Environmental Protection Agency Office to which it was submitted; and (3) The volume of fluid injected, the inje ction zone or zones into which it was injected, and the period over which injection occurred. (g) The owner or operator must retain for th ree years following si te closure, records collected during the post-injec tion site care period. The owne r or operator must deliver

the records to the Director at the conclusion of the retenti on period, and the records must

thereafter be retained at a location de signated by the Director for that purpose.

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Austin 1042121v.1Letter ID: 0223 Commenter: Darrick Eugene Organization: Texas Carbon Capt ure 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 Propos ed 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 simultane ous extraction of hydrocar bons, as in the case of enhanced oil recovery (EOR) or enha nced gas recovery (EGR) (e.g., enhanced coal bed methane or ECBM). The Proposed Rule focuses on sequestration outside the context of commercial product extr action and effectively separates CO2 injection into two classes: sequestrati on in saline or other non· hydrocarbon related target formations and hydrocarbon related sequestration. In general,

this focus reveals several concerns refl ected in the Proposed Rule that the TxCCSA hopes to address, including: 1) the lack of clarificati on of the injectate

stream which could lead to the stream be ing 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 producti on; 6) the post-inje ction site care timeframe; and 7) multi·state jurisdictional issues.

1 While the term sequestration and storag e may be used interchangeably, we prefer the term "storage," as it contem plates recovery of injected CO2 for

beneficial use. 2 See Regulatory Determination for Oil and Gas and Geothermal Exploration, Development, and Production Wastes; Re gulatory Determination, 53 Fed. Reg. 25445 (July 6, 1988) 3 See the work of Dr. Steven Bryant, dire ctor of the Geologic CO2 Storage Joint Industry Project in the Center of Petrol eum 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 Stor age: Research Path ways, Progress and Potential, Global Climate & Energy Pr oject Annual Symposium, October 2007,

available at http://pangea.stanford.edulresearctv'bens onlab/presentations/C arbon%20Dioxide%20

1CaptureYa20and%20Storage%2OY020ResearchO/020Palhways%20Progr ess'Y020and%20Potential.pdf. 7 Chiara Trabucchi and Lindene Patton, Storing Carbon: Opti onsfor Liability Risk. Management, Financial Responsibil ity, 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 Geol ogic Storage, The Interstate Oil and Gas Compact Commission, Storage of Carbon Di oxide in Geologic St ructures: A Legal and Regulatory Guide for States and Pr ovinces (Sept. 25,2007) available at http://iogcc.mysbopify.comlcollectionslfrontpagelp roductslco2-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 clarif ies that the purpose of the GS re gulation is to ensure that GS is conducted in a manner that protects USDWs fr om 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 i ssues (seeking comment)

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment)

Comment: Point #1: The lack of clarif ication 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. Neverthe less, by tracking closely the Class I rules for the injec tion 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 compos ition specification minimum for CO2, the EPA opens the door to having the CO2 injectat e stream declared a waste. We feel that is a serious weakness, compelling a regulatory approach for a worst-case injectate composition stream, and providi ng a basis for additional regulation

under the Resources Conservation and Recove ry Act (RCRA) or the Comprehensive Environmental Response, Compensation, and Li ability Act (CERCLA). The failure to define the composition specification mi nimum 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 an d geothermal energy under RCRA [FN2]

22 See Regulatory Determination for Oil and Gas and Geothermal Exploration, Development, and Production Wastes; Re gulatory 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, how ever, 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 propertie s. Specifically, the GS rule requi res the owner or operator to submit data about the site, including an analysis of the chemical and physi cal characteristics of the CO2 stream, as required at §146.82(a)(7)(iv), and informati on on the compatibility of the CO2 stream with fluids in the injection zone a nd minerals in both the in jection 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 geoche mical reactions between the injectate (CO2) and the host geologic formations, which could result in the plugging of pore sp aces or the dissolution

of formation minerals.

EPA recognizes that many CO2 streams may be rela tively 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 stream s. 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 pollu tion removal technologies.

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

to examine the issue of RCRA a pplicability to CO2 streams be ing 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 r ead 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 not es 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 systemfo r qualifying geologic storage sites. Fundamentally, the TxCCSA believes that hydrocarbon relate d geologic storage is one of the important avenues by which the next gene ration of energy pro duction will move forward. CO2 occurs naturally in the subsurface and is no stranger to geologists

3who attempt to understand fluid migration and subsurface accumulations. The fact that CO2 can be trapped in subsurface fo rmations 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 injectio n security. There is an evolving [FN3]

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

believe that such a framework is necessa ry for the insurance industry that will oversee injection in non-hydrocarbon rela ted geologic storage applications.

3 See the work of Dr. Steven Bryant, dire ctor of the Geologic CO2 Storage Joint Industry Project in the Center of Petrol eum 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, s ite characterization by the owne r or operator (under §146.82) and providing an appropriate de gree of flexibility to the Director to evaluate site-specific geologic data will afford the greatest protection of US DWs from endangerment. EPA believes that it is important for the Director to have as much site-specific informati on 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 considerin g varying site conditions eliminating the need for tiered requirements. GS in areas that may pos e 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 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: As currently written, EPA creates a separa te Class VI category of UIC regulation for CO2 storage in their attempt to avoi d the Class I waste moniker. Where CO2 storage sites can meet the qualificati ons for permitting, the TxCCSA believes that geologic storage is subs tantially similar to EOR/EGR and in those instances any regulations for Class VI wells shoul d reflect more closely UIC Class II

standards instead of the mo re stringent Class I hazardous waste well standards. If the geologic storage site doesn't qua lify or if the injectate composition is such that it is truly a waste stream, th en 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 s ites used for ER may be suitable for GS and may be among the first GS sites. However, the Ag ency believes that the nature and risks of CO2 injection for the primary purpose of long term stor age poses different risks than injection for the

4primary purpose of EOR, and therefore has devel oped new Class VI regulations to address these unique risks. For example, the volume of CO2 anticip ated 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 i nvolving large volumes of CO2 and likely having higher pressures within their stor age 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 correc tive action, well construction, ope ration, mechanical integrity testing, monitoring, well plugging, po st-injection site care, and site closure of GS wells that directly address issues unique to the natu re 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 inject ion into depleted reservoirs

Comment: Point #3: The draft rules fo cus on minimizing the number of wellbore penetrations at a geologic storage facility. The Preamb le discusses "numerous artificial penetrations" related to oil and gas reser voirs.[FN4] The TxCCSA believes this focus is misplaced and damaging because it pot entially eliminates certain target geologic formations and represents an unr ealistic approach to geologic storage.

In the first case, the best target geol ogic formations, typically producing or depleted oil and gas reservoirs, wher e geologic storage projects will be of dramatically lower ris k, have numerous wellbore pene trations from previous exploration activity. Many of those formations have proven trapping conditions for substances lighter than brine and th erefore very much like CO2. In addition, the previous exploration activity provid es the understanding of the subsurface to guide geologic storage projects. To eliminate those areas based upon a postulated concern of leakag e 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 demons trates a lack of understanding of the compartmentalization of natura l reservoir systems. It wi ll be inconceivable to expect a single well or even a single di git set of wells to accomplish geologic storage on a project of importa nt 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 corr ective action, well construction and operation, monitoring and testing, and post-in jection site care and site cl osure requirements are met under

5today’s rulemaking.

EPA maintains that minimizing the number of artificial penetrati ons in a formation is imperative for preventing endangerment of USDWs. For th is reason, the GS rule requires owners or operators to conduct an AoR study and address a ll 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 addr ess 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 prot ects 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 underst anding in how geologic storage projects would be implemented.

5 ~ Id at 43524.

Individual Response: EPA recognizes that the number of m onitoring 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 descri bed the number of monitori ng 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. Therefor e, the number of monitori ng wells was indirectly based on the size of the AoR. Because ER projec t 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 si te compared to a saline formation project. EPA retained this assumption regarding the density of injection wells fo r the final rule analysis, but it changed its assumption on the number of monitori ng wells at each site. For the final rule, the Agency assumes one monitoring well above the inj ection 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 th e 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 sensitiv ity 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

6original assumptions. This change results in a nnualized incremental rule costs approximately 16 percent less and 16 percent greate r 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 diffi cult 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 assumpti ons in the primary analysis are based on information gathered on the DOE pilot pr ojects and EPA's experience with decades of injection regulated under the UIC Program.

For additional information on EPA's final regula tory approach, includi ng 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 buoya ncy," enumerated coun tless times in the draft rules, is misleading. The Preamble to the Proposed Rule makes very clear that changes to the VIC program for CO 2 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 ga s that possesses di fferent physical properties than some othe r 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 und erground fluids or gases and less dense than others. Hence the movement of injected CO2 in a reservoir, or any type of system containi ng different fluids or gases, will vary

based on the relative densities of the vari ous 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 bo ttom, 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 ne arly 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 confin ing 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 st udy 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 fl uids adjacent to the caprock. The study could not determine if the al teration was due to expos ure from CO2 diffusion up into the overlying caprock or by upward CO 2 migration within wellbore system defects (perhaps cement-caprock and/or cement-form ation interfaces). In both studies, the CO2

7apparently moved from the underl ying reservoir into the well bor e section located within the overlying caprock. These observations, especially in conjunction with the larger CO2 volumes and higher reservoir pressu res anticipated with GS, justify the well construction requirements in the final GS rule in order to prevent deterior ation of the materials be tween the well casing and

the well bore that can result in unacceptable fluid movement.

EPA adds that buoyancy of CO2 is among several uni que 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 inje ction began. The overall behavior of CO2 at Sleipner is for it to migrate to the top of the formation and spread laterall y 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 volum e 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 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: Point #5: The lack of consider ationfor simultaneous storage and hydrocarbon production. Another concern raised by the proposed EPA rule

involves the lack of consideration fo r storage of CO2 during oil and gas production. At TxCCSA, we st rongly believe that the early CO2 captured from industry sources will be in jected in substantial volumes and stored during existing and new EaR operations. If the capturing company receives no value ("offset") for reducing emissions, th e 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 existi ng 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 comme rcial 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 Ba sin 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 EO R'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 re cognition 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

8geologic 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 regulato ry 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 site s 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 stor age poses different risks than injection for the primary purpose of ER, and theref ore has developed new Class VI regulations to address these unique risks. For example, the volume of CO2 anticip ated to be injected for long term storage is significantly greater than for ER operations. Reser voir pressure conditions will also be different, with Class VI injection opera tions 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 re quire that any owner or operato r injecting CO2 for the primary purpose of long term storage obtain a Class VI pe rmit with some special consideration for the fact that they are transitioning from a well not or iginally designed to meet Class VI requirements. The Director has the authority to determine at wh at point a Class VI permit is required for those projects that are transitioning from the primar y purpose of EOR to long term storage of CO2. The final regulation provides a set of technical factors for the Direct or to evaluate in making this determination, at §144.19. EPA believes that this approach provides su fficient protection of

USDWs when there is an increased risk to USDWs as compared to traditi onal Class II operations while allowing for site-specific flexibility.

EPA is developing guidance on transitioning perm its 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 change s in risk to USDWs from projects, and how the Director may determine whether a project should be regulated within th e Class II or Class VI UIC program. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequest ration.cfm. For more information, please

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

EPA clarifies that the GS rule does not require a ny 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)

9Comment: Point #6: The proposed Post-injection S ite Care period is too long based on prevailing science and risk profiles. Th e 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 f unction of various ge ologic trapping mechanisms, the creation of artificial im pediments to financial assurance and the sagacity of other re gulatory proposals.

First, we believe as the literature sugges ts 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 ope rational 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 s uggest "the likelihood th at 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 for ces in the interstices of the rock formation which develops about 10 years after injection; 3) dissolution or solubility trapping -where the CO2 di ssolves into the brine found in the geological formation and sinks because the CO2 saturated brine is heavier than non-CO2 saturated brine, taking place betw een 10 and 100 years after injection; and 4) finally mineralization or mineral trapping - which happens when dissolved CO2 chemically reacts with the formati on rock to produce mi nerals, a process requiring hundreds of years.[FN8]

Given that the greatest risk occurs during the operational st age of a geologic storage project and that re sidual and dissolution trappi ng start well in advance of 50 years, it is difficult to unders tand 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 mechanis ms that limit the risk of unexpected

release of CO2 after the termin ation of injection activity.

Furthermore, other respected models sugge st a much shorter period. For instance. the IOGCC Model Rules and Legislation stip ulate a 10-29 year pos t-injection site care period.[FN9] Under the IOG CC 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 car e period and until closure. This 10-29 year post-injection site care period more easily relates to the relative risks

10of geologic storage and the geochemical r eactions discussed above. Also, in the Preamble, EPA acknowledges that a 30-year post-closure care pe riod is recognized as the industry standard for the inje ction 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 Stor age: Research Path ways, Progress and Potential, Global Climate & Energy Pr oject Annual Symposium, October 2007,

available at http://pangea.stanford.edulresearctv'bens onlab/presentations/C arbon%20Dioxide%20CaptureYa20and%20Storage%2OY020ResearchO/020Palhways%20Progr ess'Y020and%20Potential.pdf. 7 Chiara Trabucchi and Lindene Patton, Storing Carbon: Opti onsfor Liability Risk. Management, Financial Responsibil ity, 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 Geol ogic Storage, The Interstate Oil and Gas Compact Commission, Storage of Carbon Di oxide in Geologic St ructures: A Legal and Regulatory Guide for States and Pr ovinces (Sept. 25,2007) available at http://iogcc.mysbopify.comlcollectionslfrontpagelp roductslco2-storage-a ·Legal·andregulatory- guide-for-states-2008. 10 See 73 Fed. Reg. at 43510.

Individual Response: EPA agrees that some owners or operat ors will be able to demonstrate, in less than 50 years, that the pr essure 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 an d evaluation of public

comments.

EPA believes that the best way to address a ll possibilities, while en suring USDW protection from endangerment, is to set a 50 year default post-injection site care timeframe, with flexibility to: (1) allow the Director discre tion 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-e ndangerment of USDWs pursuan t to requirements at §146.93(c).

EPA believes that a default post-injection site car e 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 ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters¿ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-specific data, and be based on pressure monitoring and USDW impacts.

11EPA clarifies that, in determining the post-in jection site care-timef rame for the proposed regulation, EPA reviewed industry reports, exis ting environmental programs, and initial GS research studies. EPA provided a synthesis of pe rtinent results from GS modeling studies in the preamble to the proposed regulation. Further expl anation of this analysis was included in an EPA-prepared background document that is available in the federal docket, titled ""Computational Modeling of Underground Injecti on of Carbon Dioxide for Determination of Area-of-Review and Potential Risk to Underg round 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 cessati on of injection. EPA be lieves 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 ag ree 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 re present 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 monitori ng technologies (used durin g 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 rule making. 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 fina ncial responsibil ity for the long time frames over which post-injection site care w ill be conducted. However, the Agency believes that in order to protect USDWs from e ndangerment under the SDWA operators must demonstrate under §146.85 that fina ncial 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 Director s in evaluating financial responsibility demonstrations. The guidance desc ribes the types of financial m echanisms that operators may choose to use when evaluating th e financial responsibil ity requirements for GS wells and it will

also include a section on how to estimate costs to support accu rate 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 financia l responsibility requirements (40 CFR 146.85)

Comment: Finally, when mapped to the requirement fo r financial assuran ce, this 50-year timeframe requirement raises barriers to obtaining financial assurance for prospective projects. Secti on 146.85 of the Proposed Rule requires the owner or operator to maintain financial responsi bility for correctiv e action, injection

12well plugging, post-injecti on site care and site closure. Undoubtedly owners/operators will enter the private s ector financial assurance market for some period in order to meet this requi rement. Both an uncertain or 50-year post-injection site care timeframe create impediments to financial responsibility. We believe th at an uncertain or exceed ingly long post-injection site-care period will discourage the development of private sector products to address financial responsibility and di scourage geologic storage in general.

Given the limited risk profile of th e post-operational phase of geologic storage, the impediments to financial re sponsibility and insurance caused by an uncertain or exceedingly lengthy post-in jection 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 "Computationa l Modeling of Underground Injection of Carbon

Dioxide for Determination of Area-of-Review a nd Potential Risk to Underground Sources of Drinking Water." EPA assessed various default timeframes based on additional review of research studies and evaluation of public commen ts. While numerous commenters suggested that EPA shorten the monitoring timeframe, none of the commenters provided suffi cient 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 developmen t of mineral trapping of CO2) under which the potential risks of endangering USDWs will likel y 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 supp ort a different timeframe. Furthermore, EPA believes that a 50-year default post-injection site care timeframe, as requi red 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 financia l responsibility, EPA rec ognizes 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 re sponsibility to assist owners or operators in evaluating the requirements of §146.85 and to as sist Directors in evaluating financial responsibility demonstrations. The guidance descri bes the types of financial mechanisms that operators may choose to use when evaluating th e 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.

13EPA 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 discreti on, 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-s pecific, 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 resour ces are available to prevent the endangerment of USDWs from improper plugging, remediation, and ma nagement of wells in the event that the owner or operator experiences financial diffi culties throughout the lif e 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 issu es. Finally, the scale of geologic storage projects could raise multi-state jurisdictional issues if the CO2 plume and AoR extend beyond and across state bounda ries. The proposed rule should speak to potential multi-state jurisdictional issues in a manner that avoids conflicting state requirements. For inst ance, one option would allow the well head or injection site lo cation to control jurisdicti on. This would provide a framework for addressing multi-state jurisd iction 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 am ong permitting authorities. The final Class VI GS rule, at §146.82(a)(2), requires the owner or operator to identify al l 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 involve d in any necessary processes; th is new requirement was added to the final rule at §146.82(b). The Agency encourag es transparency in the permitting process and anticipates that State-State/State-Tribal communication on GS permitting will facilitate information sharing and encourag e 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.

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

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 au thorized Class I industrial, Class II, or Class V experiment al CO2 injection projects who seek to

"convert" these wells to Class VI wells a nd 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 app lies to owners an d operators of permit or rule- authorized Class I industrial, Class II, or Class V experimental carbon dioxide injection pr ojects 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 discre tion, from the casing and cementing requirements at §§ 146.86(b) and 146.87(a)(1) th rough (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 th e final rules but should be enhanced. In addition, the rules should be expanded to provide further detail on the conversion proce ss. It is critical that ow ners 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 mo difications to existing wells. For instance, while the rules waive the Cla ss VI casing and cementing requirements for existing wells being converted to Cl ass VI wells, the rules do not address

other construction or cons truction-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 va lve 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 expe nsive. Rather than requiring existing wells to meet prescriptive rules that ma y not be necessary or applicable, the

15decision to grandfather an existing well s hould be based solely on the well’s passing a mechanical integrity test w ithout physical well modification and meeting all other Class VI permit require ments that may be met without well modification. This change could be a ccomplished 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 Cla ss VI geologic sequestration permit for

their well or wells. If the Director determines that USDWs will not be endangered THROUGH THE RESULTS OF ME CHANICAL INTEGRITY TESTING PURSUANT TO §

146.89 THAT THE WELL IS EFFECTIVE IN PREVENTING EN DANGERMENT 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 W ELL MODIFICATIONS, SUBJECT TO

MEETING ALL OTHER CLASS VI WELL REQUIREMENTS.

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

CO2 be made in the context of all available information about th e 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 protec tion 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., increase d 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-inj ection site care, and site clos ure requirements in the final GS rule. Therefore, following re-permitting, these pr ojects must be subject to the requirements in the final GS rule, including re quirements 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 suff icient 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 discu ssion 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 w ill not be allowed. While conversion of suitable Class II wells for GS is desirable in many situ ations, EPA stresses that protection of USDWs from endangerment is the primary mission and mandate of the UIC program.

16To clarify the point at which the primary purpose of CO2 injection transi tions from ER (i.e., a Class II well) to long-term storag e (i.e., Class VI), the final GS rule at §144.19 contains specific,

risk-based factors to be consid ered 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 ava ilable for the Director to determine the risk posed to USDWs from a GS/ER project, and how th e 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/g roundwater/uic/wells_s equestration.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 definiti on of Geologic Sequest ration 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 s ubsurface three-dimensional extent of the carbon dioxide plume, associat ed pressure front, and displaced brine, as well as the surface ar ea above that delineated region.

This definition restricts geologic sequestration proj ects to the lowermost formation containing a USDW. Restricting in jection formations to the lowermost USDW is not necessary for the protection of USDWs and would remove a vast number

of viable formations from considerati on. The drilling industry has shown that it can operate CO2 injection wells in an enhanced oil recovery (EOR) context without endangering USDWs that are loca ted below the injection zone. There should be no blanket prohibition agains t injection into any approved geologic

zone even if above the lowermost USDW. Th e 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 WI LL NOT ENDANGER USDWS. It includes

the subsurface three- dimensional ex tent of the carbon dioxide plume, associated pressure front, and displa ced brine, as well as the surface area above that delineated region.

17Individual Response: EPA acknowledges that there are lim ited circumstances where injection above the lowermost USDW can be performe d 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 owne rs or operators can seek a waiv er of the Class VI injection depth requirements for injecti on into non-USDW formations above and/or between USDWs. It establishes: 1) requirements spec ifying information that owners or operators must submit, and Directors must consider, in consultation with PW SS Directors; 2) procedures for public notice of a waiver application and for Director-Regiona l Administrator communicat ion; 3) the waiver issuance process; and, 4) additiona l requirements that apply to owne rs or operators of Class VI wells granted a waiver of the in jection depth requirements to en sure 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 us ed for geologic sequestration of carbon dioxide that have been granted a waiver of the injection depth requ irements pursuant to re quirements at §146.95.”

EPA believes that these requirements will ensure USDW protection while providing flexibility to UIC program Directors and owne rs or operators who undertak e CO2 injection for GS. The Agency believes this approach: 1) responds to co ncerns about local and re gional geologic storage capacity limitations imposed by th e proposed injection depth require ments; 2) allows for a more site-specific assessment of injection depth for GS projects; 3) accommodates injection into different formation types; 4) a llows 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 aqui fer exemptions for GS. Finally, EPA’s approach to addressing injection depth va riability through a waiver process responds to concerns about future drinking wa ter resource availability and the need to ensure that high quality water remains available in sufficient qua ntities to supply drinking water needs. For additional information on the waiver approach, pleas e 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/ed its 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 fo rth the information which the owner or operator must submit to the Director in or der 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 pr ior to well drilling (applicants will

not drill the well until it ha s been approved, otherwise they risk drilling an unusable well). Still other data can only be obtained after in jection activities

18have been initiated. Post drilling and post injection data should not be required as part of the application pro cess but instead should be considered confirmatory data that may be submitted af ter 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 initi al permit application, and only those data that may be reasonably obtained pr ior to commencement of installation and operation of the injection well.

EPA Proposed: §146.82 (f) Maps and st ratigraphic cros s sections indicating the genera l 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 directio n of water movement, where known;

So long as the Applicant proposes to inje ct 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 stra tigraphic cross s ections in the immediate vicinity of the proposed inject ion 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 subpa ragraph (f) should be modified as

follows:

(f) Maps and stratigraph ic cross sections indicating the general

vertical and lateral limits of all THE LOWERMOST USDWs, ALL USDWS IN

THE IMMEDIATE VICINITY OF THE PROPOS ED INJECTION WELL(S), water wells and springs within the area of review , their positions relative to the injection zone(s) and th e 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 subpar ts (l), (r) and (s) of § 146.82 cannot be met until after the well is drilled. For example, subparagraph (l) re ferences (j), formation testing. Clearly formation test ing 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)

19because 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 avai lable 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 in formation to be submitted before operation of the well is authorized (at §146.82(c)).

EPA believes that this revisi on 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 inje ction well classes, which could help avoid confusion about how to meet the permitting requirem ents 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 modifi cations and additions th at 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 se ctions for the entire extent of those USDW s above the lowermost USDW. EPA believes a thorough un derstanding of the hydrogeologi c 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/ed its 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 proj ect. 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 pr oject. 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 th at the proposed rule be amended as

20follows:

§146.84 Area of review and corrective acti on. (a) The area of review is the region surrounding the geologic seque stration project that may be impacted by the injection activity. The area of review is based on computational modeling that, TO THE EX TENT PRACTICABLE A ND 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 regulat ion and the associated background document "Computational Modeling of Unde rground Injection of Carbon Dioxide for Determination of Area-of-Review and Potential Risk to Undergrou nd Sources of Drinking Water" (cited in the proposed rule preamble as USEPA, 2008d), substa ntiates the modeling re quirements in the GS regulation and indicates that t echnology has advanced to the point that a CO2 injection project can be adequately modeled to support both pr ediction 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 scienc e 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 th e 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 physi cal and chemical propert ies of all phases of the injected CO2 stream and is based on av ailable site characte rization, 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 ensu re 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 a nd to permit appropriate testing and monitoring. The proposed rule does not ad equately 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;

21The proposed rule requires an applicant to submit to the

Director information on the corrosiven ess 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 --la boratory data for hypothetical streams, empirical testing, analogous wells? Cl arification is requested on the aforementioned requirements.

Individual Response: The GS rule at §146.86(b)(1) requires th at 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 consid er various aspects of the injec tion project, including injection pressure, external pressure, internal pressure and axial loading in §146.86(b)(1)(ii), corrosiveness of the CO2 stream, and formati on fluids in §146.86(b)(1)(v).

EPA requires under §146.90 that owners or operato rs submit proposed testing and monitoring plans to the Director at the time of the permit a pplication. 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. Monito ring wells will differ from injection wells in their intent, casing sizes, and depth, although thei r casing and cementing will likely be similar. Unlike injection wells, monitoring we lls will not need to be built to withstand CO2 injection, but, nonetheless, will need to be built with material s 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 su fficient number of centralizers, must extend to the injection zone a nd 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 form ation fluids and of su fficient quality and quantity to maintain integrity ove r 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 channe ls to ensure that USDWs are not endangered.

Additional proposed requirements affec ting 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 unn ecessary, expensive and contrary to best practices. Under acceptable best practices, the long st ring casing would

not be cemented to the surface so that the pressure between the surface casing and long string can be monitored to determ ine if there is migr ation 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. Additio nally, TxCCSA’s field data indicates that the proposed casing and cementing re quirements 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 Cl ass VI wells the cost could escalate to approximately $193,000 per well a poten tial $173,000 increase, representing a 10% increase in total per well costs.[FN1]

[FN1: For a typical well completed under Cl ass II UIC rules, the total costs equals $1,700,000.]

TxCCSA suggests an alternative that protec ts 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 cem ent additives to be compatible with

the carbon dioxide stream and formation flui ds that cover the in jection zone and the confining zone, and then require sta ndard (API, ASTM International, or comparable standards) industry cements to a certain distance above the confining zone. This would place cements that may re quire special additives at the point where USDWs are most effectively protec ted 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 supporti ng the GS Rule includes cementi ng costs of $1.20 per foot lengthinch diameter plus 25% of to tal cementing costs for use of corrosion-resistant cement. For a

23representative deep saline injection well used in the cost analysis, this translates to a total cementing cost of $406,500 per injection well, repres enting an incremental co st 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 characte ristics). While the rule requirements necessitate these additional costs, the requirements are guided by the necessity to address the unique challenges posed by CO2 injecti on (including large injection vol umes, the relative buoyancy of CO2, its corrosivity in the presence of water, th e 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/ed its to rule language

Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)

Comment: TxCCSA suggests the fo llowing revision:

§146.86 (b) Casing and Cementing of Cla ss VI Wells. (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection z one and must be cemented by circulating cement

across the surface INJECTION ZONE AND CO NFINING ZONE AND AN

AUTHORIZED DISTANCE ABOVE THE CO NFINING ZONE, SUBMITTED BY THE

PERMITTEE

AND APPROVED BY THE DIRECTOR in one or more stages.

*

*

* (5) TO PROTECT USDWS, C Cement and cement additives must be compatible with the carbon dioxide st ream and formation fluids and of sufficient quality and quantity to maintain integrity over the design OPERATING life of the WELL geologic sequestratio n 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, ra ther than the life of the sequestration project. GS projects are anticipated to ha ve 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 constructe d 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 in jection, EPA believes that Class VI wells must be designed to protect USDWs from endangerment for the life of the project. Furthermore, rigorous casing and

24cementing help ensure that the Class VI well will not serve as a conduit fo r movement of fluids associated with future injection operations. EP A believes that the requirements for long-string casing are appropriate and offer appropriate fl exibility: §146.86(b )(3) requires that the longstring casing extend to the injecti on zone and be cemented by circulating cement to the surface in one or more stages. It does not, however, sp ecify how cementing would be accomplished, and gives flexibility to the owner or operator to pr opose alternate methods to provide a sufficient

amount of cement to meet the standard that US DWs are protected from endangerment, subject to the approval of the Director.

Additionally, EPA is developing guidance on the constr uction 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 pr ior to injection well operation.

EPA’s proposed § 146.87 delineates the info rmation a permittee must collect during the drilling and cons truction of a Class VI well, prior to actual injection activities. Although the proposed rule generally allows the Director to approve alternative met hods that provide equivalent or better information, it

is not clear that the Director can utili ze 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 cas ing is set and cemented.

The requirements in §146.87(a )(2)(ii) to secure and submit specified logs before, upon and after surface casing inst allation is excessive. The proposed rule fails to provide a sufficient just ification for requiring a cement bond and variable density log before and upon inst allation of the long string casing, and requiring a temperature log after the cas ing is set and cemented. Temperature logs are seldom used in the dri lling industry to determine cement characteristics as they do not provide useful data rega rding 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 inform ation about the injection and confining zones and ensure th at 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 fr om endangerment. While the tests do provide information on some of the same items, each test provides unique pieces of information that

25build on each other and allow for interpretations not possible with a si ngle test. Existing lithologic and geologic information may lack the de tails needed for site-specific well design and the geology needed to support protecti on of USDWs from endangerment.

Letter ID: 0223 Comment ID: 23975 Letter Lines: 601 to 614

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 loggi ng tool approved by th e Director as

follows:

§146.87(a)(2)(ii) A cement bond and vari able 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: CO NSTRUCTION REQUIREMENTS.]

*

*

* (5) Any alternative methods that provide equivalent or better information and that are required of a nd/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 te mperature logs are required by §146.87(a)(2) upon installation of the surface casi ng. 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) Resi stivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any other logs the Director requires for the given geolo gy before the casing is installed;

and

Once again, the proposed rule requires tes ting 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.

26Fracture finder logs will only see mi nor 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 s ubmittal, the rules should allow the applicant to propose and justify a logg ing 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. Tx CCSA suggests the following revised rule, incorporating this proposed change:

§146.87 (a)( (3) Before and upon installa tion of the long string casing: (i) Resistivity, spontaneous potenti al, 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 test s listed at §146.87(a) are necessary to verify information about the injection and confining zone s and ensure that the well is being drilled and cased as approved and has mechanical integrity.

EPA notes that owners or operators will descri be in their permit applications how they will construct and test the well, and will also subm it site-specific information about the subsurface geology. The Director will evaluate the proposed logging activities al ong with site-specific geologic information to identify geologic data of interest.

EPA adds that, should alternative methods be show n to provide equivalent or better information or if site-specific conditions and risk factors dictate that other l ogs 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 eq uivalent or better information.

Letter ID: 0223 Comment ID: 23977 Letter Lines: 645 to 659

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)

Comment: The proposed rule also requires unnecessa ry 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 a nd variable density log, and a temperature log after the cas ing is set and cemented.

27TxCCSA suggests that the loggi ng options it recommends w ith respect to surface casing also apply for the long-string casi ng. Thus, the proposed rule should be

revised as follows:

§146.87(a)(3)(ii) A cement bond and vari able 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 ST ANDARDS APPLICABLE TO CLASS I

NONHAZARDOUS WELLS: CONSTRUC TION 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 info rmation which enhance each other and allow for interpretations not possible with a single test. For example, a va riable density log can detect microannuli, fractures, and formation effects. Te mperature logs can dete ct fluid or gas flow through channels that cannot be detect ed by either of the other tests.

Determining the quality of the cementing of the long-string casing is esse ntial to the protection of USDWs from endangerment. EPA adds that should alternative methods be shown to provide equivalent or better informati on, 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 ope rator must take and submit to

the Director whole cores or sidewall cores of the injection zone and confining system and formation fluid sa mples 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 othe r 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 th e 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 sma ll 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 unreasonabl eness of the whole core, sidewall core and extra core sampling is evident upon considerat ion of the sheer volume of physical evidence that this pr ovision alone may produce. For example, in Texas there are over 5000 existing Cl ass II CO2 injection wells. If a small

28fraction 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 agen cy store this magn itude of cuttings? This may become a particular problem give n 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 representa tive of conditions at the Class VI well. EPA clarifies that, at a minimum, repor ts 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 Ag ency'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 si dewall cores of the injec tion zone and confining system and formation fluid samples from the injec tion zone(s), and must submit to the Director a detailed report prepared by a l og analyst that includes: well lo g 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/ed its 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, TT he 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 repre sentative 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 ve rify that the site is suitable for GS.

29Letter 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 follo wing 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 characteristic s 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. Fractu re pressure is specified. Under the circumstances, fracture pressure should only be calculated, rather than "determined" as any de termination based on techniques beyond mathematical calculation will require co ring or perforation of the casing, potentially decreasing the mechanical inte grity of the well an d running directly counter to the objective of the proposed rules.

With respect to other generic data EPA seeks regarding th e 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 clarifi cation 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 determina tion of fracture pressure. The wording "determined or calculate d" 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 ow ners/operators and Dire ctors in evaluating the requirements for pre-operational logging and testing under §146.87, including providing information on the physical and chemical characte ristics of the injecti on 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/ed its 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 opera tor must provide the Director with the opportunity to witness all logging and te sting by this subpart.

30The owner or operator must submit a sc hedule of such activities to the Director 30 days prior to conducti ng the first test and submit any changes to the schedule 30 days prio r to the next scheduled test.

The agency requires the submission of a proposed logging and te sting schedule at least 30 days in advance of those pro posed activities. Although a logging and testing schedule certainly can be designe d 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 experi enced 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 an d testing by this subpart. The owner or operator must submit a PROPOS ED schedule of such activities to the Director AT LEAST 30 days prio r 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 notif ication requirement is unreasonable. The 30-day notification mirrors the current requ irement 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 protec tion 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 ope rating 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 op erating injection pressure, unless the Director determines that such requirement might harm the integrity

of the well.

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

31annulus exceeding the operat ing injection pressure will , in most cases, result

in an exceedance of the bur st pressure of the casi ng. 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 th is likelihood and thus allows the Director to waive the requirement. However, the rule sh ould 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 revisi on 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 geomechan ical properties of the site based on information collected under §146.82 and meets the constr uction requirements at §146.86 woul d be able to maintain integrity if the annulus pressure were reasonably higher than injection pressure.

The purpose of continuous pressu re monitoring (to demonstrate in ternal MI) is to demonstrate that no pressure changes are occurring, because a drop in pressure on th e 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 th e Director determines that such a requirement might ha rm the integrity of the well. The final regulation at §146.88(c) requires that the owner or operator must mainta in on the annulus a pressure that exceeds the operating injection pressure, unles s the Director determines that such requirement might harm the integrity of the we ll or endanger a USDW.

Letter ID: 0223 Comment ID: 23984 Letter Lines: 768 to 776

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4100 2.4.1 Injection parameters

Comment: problem. The suggested revisi on is encapsulated below:

(c) The owner or operator must fill the annulus between the tubing and the long string casing with a non-co rrosive fluid approved by the

Director. IF THE DIRECTOR DETERMIN ES THAT SUCH REQUIREMENT WILL NOT

HARM THE INTEGRITY OF THE WELL, Tt he owner or operator must maintain A

POSITIVE PRESSURE on the annulus a pressure that exceeds the operating injection pressure. ., unle ss the Director determines that such requirement might harm the integrity of the well.

32Individual Response: As described above, EPA disagrees th at 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/ed its 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 mon itor: 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 in stall 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 unn ecessary 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 fl uids from exiting the wellbore. They are used in off-shore operations because of the risk of damage to the wellhead from atmospheric or anthropogenic phe nomenon, such as a hurricane causing extensive platform damage or a ship collid ing with a platform. But in an onshore injection system, a down-hole shut-off sy stem 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 li mited to off-shore operations.

Furthermore, the requirement to continuously monitor the annulus fluid volume is impractical, because it does not provide a ny 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. Tx CCSA recommends the following:

§146.88(e) The owner or operator must install and use continuous recording devices to monitor: The in jection pressure; the rate, volume, and temperature of the carbon dioxid e 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

33operator 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 pe rmit. IF THE OPERATION INVOLVES OFF-SHORE INJECTION, THE OWNER OR OPERATOR MUST INSTALL AND USE

ALARMS

AND AUTOMATIC DOWN-HOLE SHUT-OFF SY STEMS, DESIGNED TO ALERT THE

OPERATOR

AND SHUT-IN THE WELL IF THE WELLHEAD IS DAMAGED OR WHEN OPERATING

PARAMETERS SUCH AS ANNULUS PR ESSURE, INJECTION RATE OR OTHER

PARAMETERS

APPROVED BY THE DIRECT OR DIVERGE BEYOND PERM ITTED RANGES AND/OR GRADIENTS SPECIFIED IN THE PERMIT;

(f) If aN down

- hole automatic shutdown is tr iggered or a loss of mechanical integrity is discovere d, 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 benefi ts of down-hole shut-off systems and considering additional research, EPA will not re quire 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 owne rs 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), requ ires 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 constructio n and operational conditions for offshore Class VI wells, including isolation from shorelines and the need to c onstruct 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 in stallation of automatic surfa ce shut-off devices for onshore wells (and affording Director's discretion to requir e down-hole devices where necessary) and

automatic down-hole shut-off devices for offsho re wells in submerged lands within the jurisdiction of a State ensures that proper pre cautions 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 su fficient to meet the intent of continuous monitoring of the pressure on th e annulus. The final GS rule at §146.90 (b) requires that owners

34or operators use continuous reco rding devices to monitor injecti on 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/ed its 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 pe r year, the owne r or operator must use one of the following methods to determine the absence of significant fluid movement under para graph (a)(2) of this section: (3) A casing inspection log, if required by the Director.

Among the test protocols prescribed by th e 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 Dir ector. Conducting a casi ng inspection log will require the tubing to be pulled from a well, and that in turn substantially increases the possibility of a well contro l event (that is a loss of control over well operation). Accordingly, the t echnique should only be mandated when other testing methodologies are unavailable. TxCCSA suggests the following edit:

§146.89(c) At least once per year, the ow ner or operator must use one of the following methods to determine the absence of si gnificant fluid movement under paragraph (a )(2) of this section: (3) A casing inspection log, if A TRAC ER 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.

35EPA 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 pr essure 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 monito r the actual volume of annular fluid in the annulus on a continuous basis, a nd 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 su fficient to meet the intent of continuous monitoring of the pressure on th e annulus. The final GS rule at §146.90 (b)) requires that owners or operators use continuous reco rding devices to monitor injecti on 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/ed its to rule language

Comment Code: 4630 2.6.3 Corrosion monitoring

Comment: EPA Proposed §146.90(c) Corrosion monito ring of the well materials for loss of mass, thickness, cracking, pit ting and other signs of corrosion must be performed on a quarterly ba sis to ensure that the well components meet the minimum standa rds for material strength and performance set forth in § 146.86(b) by: (1) Placing coupons of the well constr uction 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 met hod 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 Di rector) will not provide meaningful information regarding the mechanical in tegrity 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 satura ted 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_ar chived/aogrcojan04.htm (From the processing/injection standpoint, CO2 is noncorrosive as long as it is dry. Proving that point, Kinder Morgan has hydr o-tested the 32-yea r-old CRC Pipeline built in 1971 to transport CO 2. 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 R eef Carriers CO2 Pipeline, 2003 CO2 Flooding Conference, December 11-12, 2003, Midla nd,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 SA TURATED 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 constr uction 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 met hod 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 ma de 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 (incl uding 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 a nd a limited number of field studies have investigated and

characterized the effects of carbonic acid on well materials. La boratory studies (e.g., Kutchko et al., 2007; Kutchko et al., 2008) cons istently identify al terations (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 b een used successfully by Class I

37hazardous waste injection well owners or operators.

Currently, there are only a few analyses of cemen t from wells that have been in prolonged

contact with CO2 in actual fiel d (down-hole) conditions. Evaluati on of cement from a well at the Scurry Area Canyon Reef Operator s Committee (SACROC) site s howed alteration, but did not show degradation that compromise d the structural integrity of th e 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 addre sses the effects of corrosion of st eel tubing and pipes. Lopez et al. (2003) noted that 60 percent of oilfield failures are re lated to the effects of carbonic acid from produced brines on carbon and low alloy steels.

Laboratory investigation of cement alteration/de gradation is an ongoing re search area. Few fieldbased studies have been completed to date. The laboratory and field stud ies currently available suggest that corrosion problems can be managed; however, there is no t a large enough body of research to rule out potentia l corrosion problems of steel co mponents of injection wells. The IPCC (2005) report on carbon dioxide capture an d storage reviewed oil and gas industry experience with gas injection we lls, close industry analogues to CO2 injection wells. The report stated that while the design of CO2 injection we lls will be very similar to gas injection wells, most down-hole components of the CO2 injecti on wells will “need to be upgraded for higher pressure ratings and corrosion resistance.” Give n 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 th at corrosion monitoring in the down-hole environment is justified. For thes e reasons, the final ru le 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 modificatio ns 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 test ing 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?

38Individual Response: EPA expects that the Director woul d 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, upgr ade, and improve computational modeling of the area of review eval uation 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 Di rector undefined discretion to order unlimited and unspecifi ed additional monitoring to improve modeling and ensure compliance. Vesting the Director with such additional undefined discretional authority increases th e 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 anopen- ended power to require "any" additional monitoring, at this early stag e, 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 co sts, creating a barrier to capital formation and discourage geologic seque stration. Accordingly, TxCCSA would recommend deleting this section:

§146.90(i) Any additional monitoring, as required by the Director, necessary to support, upgrade, and imp rove computational modeling of the area of review evaluation require d under § 146.84(b) and to determi ne compliance with standards under 40 CFR 144.12.

Individual Response: EPA does not believe that Director s 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 m onitoring 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 technologie s and recommended approaches for implementing a testing and monitoring pla n, including pre-operatio nal geophysical logging

39and testing of injection wells, MITs, injection well testing during opera tion, 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/ed its to rule language

Comment Code: 5100 2.8.1 Injection well plugging activ ities (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 wellbor e to be flushed prior to plugging and thus it is unnecessary to use cemen t "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 t ype 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 potentia lly 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 retain s 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-injecti on timeframe (seeking comment)

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

The proposed rule establishes a 50 year default period for pos t-injection site care. There is, however, no factual or scie ntific basis for such an extensive period. Under EPA’s Resource Conservation an d Recovery Act rules, which regulate the disposal of hazardous wastes, post closure care is limited to 30 years. Defaulting to an excessively long peri od will increase cost s and introduce

40greater regulatory uncertainty, which w ill discourage capital formation around CO2 sequestration.

Additionally, even though the proposed rule appears to in clude 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 re port. 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 s ite 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 th e post-injection site care period. These

Individual Response: Because of the variety of site-speci fic circumstances at GS sites, EPA

believes that individual UI C Directors, in consultation with oper ators, will be in the best position to determine whether additional post-injection site care monitoring is needed (or whether the timeframe may be shortened), ba sed on the circumstances of a pa rticular project. EPA expects

this decision to be made based on relevant site data and in consultati on with all potentially impacted parties, and will not be made arbitrarily.

EPA believes that 50 years is an appropriate defa ult post-injection site care timeframe. However, EPA recognizes that, in some cases, the post-in jection site care timefra me may need to be lengthened or shortened based on site-specific circumstances. For instance, if after 50 years, monitoring data indicates that the CO2 plum e is still moving and may endanger a USDW, monitoring should continue on a regu lar basis. Conversely, if it can be demonstrated in less than 50 years that the plume and pressure front no lo nger pose a risk of endangerment to USDWs, continuing post-injection site care wo uld 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, EP A reviewed industry reports, existing environmental programs, and initial GS research studies. EPA provided a synthesis of pertinent results from GS modeling studies in the preambl e to the proposed regula tion. Further explanation of this analysis was included in an EPA-prep ared background document that is available in the federal docket, titled "Computa tional Modeling of Underground In jection of Carbon Dioxide for

Determination of Area-of-Review and Potentia l Risk to Underground Sources of Drinking Water." Based on review of these studies, m odeling results indicate that the CO2 plume stabilization may occur on the timeframe of 10- 100 years after the cessa tion of injection. EPA believes that a 50-year default post-injection si te 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 de monstrated that the CO2 plume

41and pressure front no longer pose a risk of e ndangerment to USDWs. For this reason, the final regulation retains the requirement at §146.93(b)(3) th at 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 pr oject 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 suggesti on 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 demonstr ated that the CO2 plume and pressure front no longer pose a risk of endangerment to USDWs. Fo r 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 author ities 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/ed its 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 th e post-injection site care period. These changes are contained in th e suggested text below:

§ 146.93 Post-injection site car e and site closure. (a) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan for post-injectio n 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 app lication 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 si te closure as demonstrated in

the area of review evaluati on required under § 146.84(b); (iii) A description of pos t-injection monitoring location, methods, and proposed frequency; and (iv) A proposed schedule for submitting post-injection

42site care monitoring results to the Director. (3) Upon cessation of injection, owne rs or operators of Class VI wells must either submit an amended post-injection site care and site closure plan or demonstrate to the Di rector through monitoring data and modeling results that no amendmen t to the plan is needed. (4) The owner or operator may m odify 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 mon itor 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 sequestra tion project does not pose an endangerment to USDWs. (4) IF WITHIN 180 DAYS AFTER THE SU BMITTAL OF THE DA TA 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 OPER ATOR OF HIS DETERMINATION AND THE

BASIS THEREFORE, AND If such a demonstr ation 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 SU BMITTAL OF THE DA TA REQUIRED UNDER SUBPARAGRAPH (3) AB OVE THE DIRECTOR FAILS TO DETERMINE AND TO

NOTIFY THE OWNER OR OPERATOR TH AT THE GEOLOGICAL SEQUESTRATION

PROJECT

MAY CONTINUE TO POSE AN ENDANGERM ENT 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 s ite closure. At this time, if any changes have been made to the origin al post- injection site care and site closure plan, the owner or opera tor must also provide the revised plan. At the discretion of the Direct or, a shorter notice period may be

allowed. (d) After the Director has authorized site closure OR SITE CLOSURE IS

43AUTHORIZED BY RULE, the owner or opera tor 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 ope rator must submit a site closure report within 90 days that must ther eafter be retained at a location designated by the Director. Th e report must include: (1) Documentation of appropriate injection and monitoring well plugging as specified in § 146.92 and para graph (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 Ad ministrator of the appropriate EPA Regional Office; (2) Documentation of appropriate notification and information to such State, local and tribal authori ties as have author ity over drilling activities to enable such State and local authorities to impose appropriate conditions on subseque nt drilling activities that may penetrate the injecti on 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 Clas s 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 pe rpetuity provide any potential purchaser of the pr operty the following information: (1) The fact that land has b een used to sequester carbon dioxide; (2) The name of the State agency, local authority, and/or tribe with which the survey plat was file d, 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 th e post-injection site care period. The owner or operator must deliver th e 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 year s, with Director's di scretion to shorten or lengthen this timeframe, combined with a site-s pecific Director’s disc retion to create an alternative PISC time frame, ensu res that USDWs are protected. The GS rule offers owners or

4445 operators flexibility regarding th e duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengt hen the PISC timeframe during the PISC period based on sitespecific data, pursuant to require ments at §146.93(b); or (2) afford ing the Director discretion to allow a Class VI well owner or operator to demo nstrate, based on substa ntial 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 th e 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 car e 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 ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-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 propo sed well plugging plans a nd post-injection site care and site closure plans under §146.92 a nd §146.93. The guidance describes recommended approaches for how an owner or operator coul d plug injection and m onitoring 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 h ttp://water.epa.gov/type /groundwater/uic/wells_sequestration.cfm.