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.December 2 3 , 2008

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Part 144 1. The authority citation for part 144

continues to read as follows:

Authority: 42 U.S.C. 300f et seq.; Resource Conservation and Recovery Act, 42 U.S.C. 6901 et seq.

144.1 2. Section 144.1 is amended as follows:

Adding new paragraph (f)(1)(viii); and

b. Revising the first two sentences in paragraph (g) introductory text.

* * * * *

(f) * * *

(1) * * *

(viii) Subpart H of this part sets forth requirements for owners o r operators of Class VI injection wells.

* * * * *

(g) Scope of the permit or rule requirement. The UIC Permit Program regulates underground injections by six classes of wells (see definition of  ̳ ̳well injection,‘‘ § 144.3). The six classes of

wells are se t forth in § 144.6. All owners or operators of these injection wells must be authorized either by permit or rule by

the Director. * * *

144.3 Enhanced Oil Recovery (EOR) or enhanced gas recovery (EGR) means any activity that uses fluids, gases or other means to improve or increase extraction of hydrocarbons. The definition of EOR is necessary to support

further comments and discussion below.December 2 3 , 2008

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144.6 3. Section 144.6 is amended as follows:

Revising paragraph (e); and

b. Adding new paragraph (f).

* * * * *

(e) Class V. Injection wells not included in Class I, II, III, IV, or VI. Specific types of Class V injection wells are described in § 144.81.

(f) Class VI. Wells used for geologic sequestration of carbon dioxide beneath

the lowermost formation containi ng a USDW. Sections 144.6,

– Classification of Wells:

(b) Class II. Wells which inject fluids :....

(4) For enhanced recovery of oil or natural gas where geologic sequestration is occurring during or in connection with enhanced recovery of oil or natural g as provided (i) there is reasonable expectation of more than insignificant future production volumes or rates as a result of carbon dioxide injection and (ii) operating pressures are no higher than reasonably necessary to produce such volumes or rates; and

(5) F or geologic sequestration in oil and gas

formation s and where the criteria of paragraph (b)(4) are not met

(f) Class VI. Wells used exclusively for geologic sequestration of carbon dioxide streams

. beneath the lowermost formation containing a
USD W Wells where geologic sequestration of CO2 streams occurs during or in connection with EOR or EGR are regulated under Class II. Additionally, t here should not be a blanket prohibition concerning injection above USDW‘s or at specific depths

. This is especially true given the possibility of changes
in the definition of a USDW to include formations greater than 10 ,000 parts per
million T otal D issolved S olids

. This requirement is not necessary for the protection of USDWs and would remove a

vast number of viable formations from consideration. Industry has shown that it can operate CO2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent example is the Salt Creek EOR project in Wyom ing, which has a USDW below the injection zone. Moreover, under the proposed rule, there are other measures that would provide real assurance of formation integrity and require operators to demonstrate that their project will not endanger USDWs, making th e lowermost USDW restriction

unnecessary.December 2 3 , 2008

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144.15 4. Adding § 144.15 to read as follows.

§ 144.15 Prohibition of non

experimental Class V wells for geologic sequestration.

The construction, operation or maintenance of any non

- experimental Class V geolog ic sequestration well is prohibited.

144.18 5. Adding § 144.18 to read as follows.

§ 144.18 Requirements for class

VI wells.

Owners or operators of Class VI wells must obtain a permit. Class VI wells are not authorized by rule to inject.

144.36 6. Section 144.36 is amended by

revising the first two sentences in paragraph (a) to read as follows:

§ 144.36 Duration of permits.

(a) Permits for Class I and V

wells shall be effective for a fixed term not to exceed 10 years. UIC Permits for Class II, I II and VI wells shall be issued for a period up to the operating life of the facility. * * *

* * * * * (a) Permits for Class I and V wells shall be

effective for a fixed term not to exceed 10 years. UIC Permits for Class II and III and VI wells shall

be issued effective for a period up to the operating life of the facility. Permits for Class VI wells shall be effective for the period through site

closure. Permits are necessary for Class V I wells through the end of the post closure moni toring phase, which is consistent with the term site closure in the amended requirement.

7. Section 144.39 is amended by revising the second sentence in paragraph (a) introductory text and by revising the second sentence in paragraph (a)(3) introduct ory text to read
as follows:

§ 144.39 Modification or revocation and reissuance of permits.

* * * * *

144.39 (a) * * * For Class I hazardousDecember 2 3 , 2008

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waste injection wells, Class II, Class III or Class VI wells the following may be

causes for revocation and reissuance as well as modification; and for all other wells the following may be cause for

revocation or reissuance as well as modification when the permittee requests or agrees. * * *

* * * * *

(3) * * * Permits other than for Class I hazardous waste injection wells, Class II, Class III or Class VI wells may be modified during their terms for this cause only as follows: * * *

* * * * *

144.51 8. Section 144.51 is amended

by revising the first s entence in paragraph (q)(1) and the first sentence in paragraph (q)(2) to read as follows:

§ 144.51 Conditions applicable to all permits.

* * * * *

(q) * * *

(1) The owner or operator of a Class I, II, III or VI well permitted under

t his part shall establish mechanical integrity prior to commencing injection or on a schedule determined by the
Director. Thereafter the owner or operator of Class I, II, and III wells must maintain mechanical integrity as defined in § 146.8 and the owner or operator of
Class VI wells must maintain mechanical integrity as defined in § 146.89 of this chapter. * * *

(2) When the Director determines that a Class I, II, III or VI well lacks mechanical integrity pursuant to § 146.8 or § 146.89 for Class VI of this chapter, he/she shall give written noticeDecember 2 3 , 2008

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of his/ her determination to the owner or operator. * * *

* * * * *

144.52 9. Section 144.52 is amended

by revising paragraph (a)(8) to read as

follows:

§ 144.52 Establishing perm it

conditions.

(a) * * *

(8) Mechanical integrity . A permit for any Class I, II, III or VI well or injection project which lacks mechanical integrity shall include, and for any Class V well may include, a condition prohibiting injection operations until the permittee shows to the satisfaction of the Director under § 146.08 or § 146.89 for

Class VI that the well has mechanical integrity.

* * * * *

144.55 § 144.55 Corrective action.

(a) Coverage. Applicants for Class I, II, (othe r than existing), III or VI injection well permits shall identify the

location of all known wells within the injection well‘s area of review which penetrate the injection zone, or in the case of Class II wells operating over the fracture pressure of the in jection formation, all known wells within the area of review penetrating formations affected by the increase in pressure. Applicants for Class VI shall perform corrective action as specified in § 146.84.* * *

* * * * *December 2 3 , 2008

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144.80 11. Section 144.80 is amended

by revising the first sentence in paragraph (e) and by adding paragraph (f) to read as follows:

§ 144.80 What is a Class V injection

well?

* * * * *

(e) Class V

. Injection wells not included in Class I, II, II I, IV or VI. * * *

(f) Class VI . Wells used for geologic sequestration of carbon dioxide. b) Class II. Wells which inject fluids:..... ( 4) For enhanced recovery of oil or natural gas where geologic sequestration is occurring during or in

connection with enhanced recovery of oil or natural gas provided (i) there is reasonable expectation of more than insignificant future production volumes or rates as a result of carbon dioxide injection and (ii) operating pressures are no higher than reasonably neces sary to produce such volumes or rates; and

(5) F or geologic sequestration in oil and gas

formation s and where the criteria of paragraph (b)(4) are not met

(f) Class VI. Wells used exclusively for geologic sequestration of carbon dioxide streams

. Wells where geologic sequestration of CO2 streams occurs during or in connection with EOR or EGR are regulated under Class II. See 144.6

Part 146 12. The authority citation for part

146 continues to read as follows:

Authority: Safe Drinking Water Act 42, U. S.C. 300f et seq.; Resource Conservation and Recovery Act, 42
U.S.C. 6901 et seq

.

146.5 13. Section 146.5 is amended

as follows:

a. Revising the first sentence in paragraph (e) introductory text; and

b. Adding paragraph (f).

(f) Class VI. Well s used for geologic sequestration of carbon dioxide beneath the lowermost formation containing an underground source of drinking water (USDW). b) Class II. Wells which inject fluids :..... (4) For enhanced recovery of oil or natural gas where geologic sequ estration is occurring during or in connection with enhanced recovery of oil or natural gas provided (i) there is reasonable expectation of more than insignificant future production volumes or rates as a result of carbon dioxide injection and (ii) operatin g pressures are no higher than reasonably necessary to produce such volumes or rates; and

(5) F or geologic sequestration in oil and gas

formation s and where the criteria of paragraph (b)(4) are not met See 144.6December 2 3 , 2008

7 Rule

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(f) Class VI. Wells used exclusively for geologic sequestration of carbon dioxide streams

. Beneath the lowermost formation containing an underground source of drinking water (USDW). Wells where geologic sequestration of CO2 streams occurs during or in connection with EOR or EGR are regulated under Class I I.

146.2 5 Geologic sequestration in oil or gas

reservoirs

without

enhanced recovery of

oil or natural

gas Wells used for geologic sequestration and meeting the classification criteria of section 146.5(b)(5) shall be subject to the following

req uirements:

(a) Existing wells that meet or exceed the construction requirements of § 146.22 shall be subject to Part 146, Subpart H [as revised by API] except sections 146.86 and 146.87. (b) New wells must met the construction requirements of section 146.22 and are subject to Part 146, Subpart H [as revised by API] except
sections 146.86 and 146.87 Details of what would be required of ―Class IIB‖ wells are to be worked out during future

discussions of the Multi

- Stakeholder Discussion Group (MSDG). How ever, API offers this language which is consistent with changes API had suggested before discussions with the MSDG began (see Section 146.81(c)). These suggestions are

– as noted

– contingent on EPA‘s adoption of API‘s changes to Part 146, Subpart H.

Par t 146

Subpart H 14. Subpart H is added to read as

follows:

Subpart H

— Criteria and Standards Applicable to Class VI Wells

Sec.

146.82 Required Class VI permit

information.

146.83 Minimum criteria for siting.

146.84 Area of review and corrective

action.

146 .85 Financial responsibility.

146.86 Injection well construction requirements.

146.87 Logging, sampling, and testing prior to injection well operation.December 2 3 , 2008

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146.81 Applicability. (a) This subpart establishes

criteria and standards for underground injection control programs to regulate Class VI carbon dioxide geologic sequestration injection wells.

(b) This subpart applies to wells used to inject carbon dioxide specifically for the purpose of geologic sequestration, i.e., the long

- term containment of a g aseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. (b) This subpart applies to wells used to inject

carbon dioxide exclusively for the purpose of geologic sequestration, i.e., the long

- term
containment of a gaseous, li quid or supercritical carbon dioxide stream in subsurface geologic

formations. It is recognized that some activities conducted under Class II, including CO2 based EOR or EGR may sequester a portion of the

carbon dioxide stream used for EOR or EGR.

This s ubpart does not apply to injection of a carbon dioxide stream for purposes of EOR or EGR even though geologic sequestration of carbon dioxide may occur during or in connection with EOR or EGR operations and/or activities. See 144.6

Deleted ―gaseous, liqui d or supercritical‖
because it was added to the definition of CO2

stream.

(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 a pply for a Class VI geologic sequestration permit

for their well or wells. If the Director
determines that USDWs will not be endangered, such wells are exempt, at the Director‘s discretion, from the casing and cementing requirements at §§ 146.86(b) and 14 6.87(a)(1) through (3). (c) This subpart applies to owners and operators of permit or rule

- authorized Class I industrial,

Class II

, or Class V experimental carbon dioxide injection projects who seek to apply for a Class VI geologic sequestration permit for their well or
wells. If the Director determines that USDWs will not be endangered, such wells are exempt, at the Director‘s discretion, from the casing and cementing requirements at §§ 146.86(b) and 146.87(a)(1) through (3). The reference to Class II wel ls in s ection 146.81(c) is no longer needed due to addition

of 146.25.

However, if EPA were not to adopt section 146.25, API would suggest the following

revisions:

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

- authorized Class I

indust rial, Class II who have ceased and will no longer continue EOR or EGR operations or

activities , or Class V experimental carbon dioxide injection projects who seek to apply for a Class VI geologic sequestration permit

for their well or wells. If the Directo r determines that USDWs will not be endangered, such wells are exempt, at the Director‘s discretion, from the casing and cementing requirements at §§ 146.86(b) and 146.87(a)(1) through (3). Class VI requirements. Class II wells permitted for CO2 injection and that have demonstrated MIT are exempt from the requirements at §§146.86December 2 3 , 2008

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and 146.87.

The language allows for the transition of Class II wells to Class VI operations. These wells

should be allowed to inject CO2 for storage based on their history of sou nd performance under the Class II program as demonstrated by MIT results. The language also allows the Director to exercise discretion to exempt other Class VI requirements.

146.81(d)

Definitions (d) Definitions. The following

definitions apply to t his subpart. To the

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

Area of review means the region surrounding the geologic sequestration project that may be impacted by the injection activity. The area of review is based on computational modeling that accounts for the physical and chemical properties of all phases of the injected

carbon dioxide stream. Area of review means the region surrounding the geologic sequestration project that may be impacted by the injec tion activity. The area of review is based on computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon

dioxide stream. subsurface three

- dimensional extent of the carbon dioxide plume, associated

pre ssure front, as well as the overlying
formations and surface area above that delineated region. Defining the AOR based on the extent of the CO2 plume and its associated pressure front is a more direct approach, rather than the approach offered by the E PA. The EPA definition suggests that the computational approach defines the AOR rather than the potential risks of the injection activity.

Carbon dioxide plume means the underground extent, in three dimensions, of an injected carbon dioxide stream.

Carb on dioxide stream means carbon dioxide that has been captured from an emission source (e.g., a power plant), plus incidental associated substances

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

added to the stream to enable o r improve the injection process. This subpart does not apply to any carbon dioxide stream

that meets the definition of a hazardous waste under 40 CFR part 261. Carbon dioxide stream means carbon dioxide , in

a ny physical state or form

, and any associate d

substances derived from the that has been captured from an emission source (e.g., a power plant), plus incidental associated substances

derived from the source materials and the capture process, and any

, its processing

, or substances added to enable or i mprove the injection process. This subpart does not apply to any carbon dioxide stream that meets the
definition of a hazardous waste under 40 CFR Source of CO2 is not an issue in the context of defining the CO2 stream. The rule applies

to th e injection of CO2 and should not address the origins of the materials since that is beyond the scope of this regulation. Original text would have precluded injection of

CO2 from some sources.December 2 3 , 2008

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part 261.

Confining zone means a geologic formation, group of format ions, or part of a formation stratigraphically overlying the injection zone that acts as a barrier to

fluid movement.

Corrective action means the use of Director approved methods to assure

that wells within the area of review do not

serve as conduits for the movement of fluids into underground sources of drinking water (USDW).

Geologic sequestration means the long

term containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. This term does not appl y to its capture or transport. Geologic sequestration means the long

- term
containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. This term does not apply to its capture or transport. Added to definition of carbon dioxide stream,

so not needed here.December 2 3 , 2008

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

carbon dioxide stream beneath the lowermost formation containing a USDW.

It includes the subsurface three

dimensional extent o f the carbon dioxide plume, associated pressure front, and displaced brine, as well as the surface area above that delineated region. Geologic sequestration project means an injection well or wells used to emplace a carbon

dioxide stream beneath the lowerm ost formation containing a USDW into an injection zone exclusively for the purpose of geologic sequestration. It includes the subsurface three

dimensional extent of the carbon dioxide plume, associated pressure front, and displaced brine,

as well as the s urface area above that delineated region. There should not be a blanket prohibition concerning injection above USDW‘s or at specific depths. This requirement is not necessary for the protection of USDWs and

would remove a vast number of viable

formations from consideration. Industry has shown that it can operate CO2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW

below t he injection zone. Moreover, under the proposed rule, there are other measures that would provide real assurance of formation integrity and require operators to demonstrate that their project will not endanger USDWs, making the lowermost USDW restriction

unnecessary.

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

a formation that is of sufficient a real extent, thickness, porosity, and permeability to receive carbon dioxide through a well or wells associated with a geologic s equestration project. Injection zone means a geologic formation, group of formations, or part of a formation that is of sufficient areal extent, thickness, porosity, and permeability to receive carbon dioxide receiving

fluids through a well or wells assoc iated with a geologic sequestration project Existing definition in the CFR is sufficient and does not need to be changed. Furthermore, adding the sufficiency requirement is not a
definitional issue and should be dealt with

elsewhere.

Post

- injection sit

e care means appropriate monitoring and other actions (including corrective action) needed following cessation of injection to assure that USDWs are not endangered as required under § 146.93. Post

- injection site care means appropriate monitoring and other actions (including corrective action) needed following cessation of injection to assure that USDWs are not endangered , as required under § 146.93. Deleted ―appropriate‖ because the definition

of it is not clear.

Deleted USDW phrase because it is incorporate d in 146 requirements.

Pressure front means the zone of elevated pressure that is created by the injection of carbon dioxide into the subsurface. For the purposes of this subpart, the pressure front of a carbon dioxide plume refers to a zone where

there is a pressure differential sufficient to cause the movement of injected fluids Pressure front means the zone of elevated pressure that is created by the injection of the

carbon dioxide stream into the subsurface

, For

the purposes of this subpart, the pressure front of a carbon dioxide plume refers to a zone where there is a pressure differential sufficient to cause

movement of injected fluids the carbon dioxide

stream or formation fluids from the injection zone Clarification.December 2 3 , 2008

12 Rule

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or formation fluids into a USDW. into a USDW

.

Site closure the point/time, as determined by the Director following the requirements under § 146.93, at which the owner or operator of a GS site is released from post

- injection site care responsibilities. Site closure means the point/ti me, as determined by the Director following the requirements under §146.93, at which the owner or operator of a GS

site project is released from post

- injection site care responsibilities. ―GS project‖ is consistent with other

definitions

.

Transmissive f

ault or fracture means a fault or fracture that has sufficient permeability and vertical extent to allow

fluids to move between formations. Transmissive fault or fracture means a fault or fracture that has sufficient permeability and

vertical extent to all ow fluids to move between

formations beyond the confining zone. The term "between formations" is inaccurate since there can be multiple formations within a injection zone. The critical factor for transmissivity is movement of injected or displaced fluids beyond the confining zone.

146.82 Required Class VI permit information

This section sets forth the information which the owner or operator must submit to the Director in order to be permitted as a Class VI well. The application for a permit for constru ction and operation of a Class VI well must include the following:

146.82(a) (a) Information required in 40 CFR

144.31(e)(1) through (6);

(b) A map showing the injection well(s) for which a permit is sought and the applicable area of review. Withi n the area of review, the map must show the number, or name and location of all injection wells, producing wells, abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, State or EPA approved subsurface cleanup sites, surface bodies of w ater, springs, mines (surface and subsurface), quarries, water wells and other pertinent surface features including structures intended for human occupancy and

roads. The map should also show faults, (b) A surface map showing the proposed

locations for the injection well(s) for which a permit is sought and the applicable area of review. Within the area of review, the map must show the number, or name and locat ion of all

known injection wells, producing wells, abandoned wells, plugged wells or dry holes, deep strata graphic boreholes, State or EPA approved subsurface cleanup sites, surface bodies of water, springs, mines (surface and subsurface), quarries, water wells and other pertinent surface features including structures intended for human occupancy and roads. The map should also show faults, if known or suspected. Only information of public record is F aults are not shown on maps unless there is a surface expression of the fault. Also, faults are detailed in (d) below and this language appears redundant.

The word ―known‖ needs to be added to remove any implication that an applicant has

to conduct studies to determine the l ocation of wells that are not currently documented in
some fashion.December 2 3 , 2008

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if known or suspected. Only information of public reco rd is required to be included on this map; required to be included on this map;

(c) The area of review based on modeling, using data obtained during logging and testing of the well and the formation as required by paragraphs (l), (r), and (s) of this section; (c ) A map delineating the area of review based

on upon modeling, using all available data including data obtained during logging and testing of the well and the formation as required by paragraphs (l), (r), and (s) of this section any wells in the area of re view This appears to be related to a condition where a well is already drilled. This does not align with requesting information to receive a permit.

(d) Information on the geologic structure and hydrogeologic properties of the proposed storage site and overlying formations, including:

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

(2) Location, orientation, and properties of known or suspected faults and fractures that may transect the confining zone(s) in the area of review and a

determination tha t they would not interfere with containment; (d) Known information on the geologic structure

and hydrogeologic reservoir properties of the proposed storage site and overlying formations, including:

(1) Isopach maps and of the proposed injection

and confini ng zone(s), a structural contour map hung on the top of the proposed injection zone, and at least two geologic cross sections of the

area of review showing the geologic formations from the surface to total depth.

(2) Location, orientation, and properties of known or suspected subsurface faults and fractures that may transect the confining zone(s) in the area of

review and a determination that they would not

interfere with containment ; If the information is not known, it cannot be reported.

―Reservoir‖ and changes to (1) and (2) are

technical corrections.

Fractures generally can‘t be identified until a well is drilled and evaluated. Even then, only fractures in the immediate vicinity of the

wellbore can be identified.

This responsibility is best left wi th EPA.

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

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

(4) Data on the depth, areal extent, thickness, mineralogy, porosity, permeabil ity and capillary pressure of the injection and confining zone(s); including geology/facies changes based on field data which may include geologic cores, outcrop data, seismic surveys, well logs, (3) Information on seismic history that have affected the proposed area of review

, including knowl edge of previous seismic events

, including the presence and depth of seismic

sources and a determination that the seismicity

would not interfere with c ontainment ;

(4) Data on the depth, areal extent, thickness, mineralogy, porosity, permeability and capillary reservoir pressure of the injection and confining zone(s) within the area of review ; including geologic /facies changes based on field

data which m ay include geologic cores, outcrop Information on seismic history should have some degree of relevance to the project.

This responsibility is best left with EPA.

Deleted capillary pressure because it is t oo h ard to measure outside of the lab. Using

s idewall c or es, it may be difficult to determine capillary pressure. Additionally, full cores areDecember 2 3 , 2008

14 Rule

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and names and lithologic descriptions;

(5) Geomechanical in formation on fractures, stress, ductility, rock strength, and in situ fluid pressures within the confining zone; and

(6) Geologic and topographic maps and cross sections illustrating regional geology, hydrogeology, and the geologic structure of the local area. data, seismic surveys, well logs, and names and lithologic descriptions;

(5) Known g eomechanical information on fractures, stress, ductility, rock strength, and in situ fluid pressures within the confining zone(s)

within the area of review ; and not available until after the well being permitted is drilled.

146.82(e) (e) A tabulation of all wells within

the area of review which penetrate the injection or confining zone(s). Such data must include a description of each well‘s type, construction, date drilled, location, depth, record of plugging and/ or completion, and any additional information the Director may require; (e) A tabulation record of all w ells artificial penetrations within the area of review which penetrate that reach the injection or confining zone(s). Such data as available in the public record must include a description of each

well‘s penetration‘s type, construction, date drilled, lo cation, depth, record of plugging and/ or completion, and any additional information the Director may require; Artificial penetrations is a more inclusive term.

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

and lateral limits of all USDWs, water wells and springs within the area of review, their positions relative to the injection zone(s) and the direction of water movement, where known; (f) Maps and stratigraphic cross sections indicating the general vertical and lateral li mits of all USDWs, water wells and springs within the area of review, their positions relative to the injection zone(s) and the direction of water movement, where known; Potentiometric (water level) surface map(s) of existing aquifers being utilized as pr ivate or public water supplies and the direction of groundwater flow in these aquifers within the area of review. At least two geologic cross sections showing the thickness and general vertical and lateral limits of all
USDWs within the area of review.

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

review Compilation of available geochemical data on the proposed i njection zone and nearest porous and permeable formation above the confining zone. Limits the data to be submitted to available information and to the injection zone and the zone immediately above the confining zone

which are the zones most likely to be monitored for potential CO 2 leakage.December 2 3 , 2008

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(h) Proposed operating data:

(1) Average and maximum daily

rate and volume of the carbon dioxide
stream;

(2) Average and maximum injection pressure;

(3) The source of the carbon dioxide stream; and

(4) An analysi s of the chemical and physical characteristics of the carbon dioxide stream; (h) Proposed operating data:

(1) Average and maximum daily injection rate and volume of the carbon dioxide stream;

(2) Average and maximum surface injection pressure; Technic al clarifications.

146.82(i) (i) The compatibility of the

carbon dioxide stream with fluids in the injection zone and minerals in both the injection and the confining zone(s),

based on the results of the formation testing program, and with the materials used to construct the well;

(j) Proposed formation testing program to obtain an analysis of the chemical and physical characteristics of the injection zone and confining zone;

(k) Proposed stimulation

program and a determination that

stimulation will not interfere with

containment ;

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

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

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

subsurface construction details of the well;

(o) Injection well construction (n) A wellbore schematic or other appropriate drawings of the surface and of the

subsurface constr uction details of the well and

surface wellhead construction. This responsibility is best left with EPA.

Technical clarification.December 2 3 , 2008

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Provision EPA Proposal API Comments Rationale

procedures that meet the requirements of § 146.86;

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

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

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

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

(t) A demonstration, satisfactory

to the Directo r, that the applicant has met the financial responsibility requirements under § 146.85; q) The Any status of corrective action on wells in the area of review; Clarifies that wells not needing corrective

action will not have a corrective action status.

146.82(u) (u) Proposed testing and

monitoring plan required by § 146.90;

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

(w) Proposed post

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

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

(y) Any other information requested by the Director.December 2 3 , 2008

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Provision EPA Proposal API Comments Rationale

146.83 Minimum criteria for siting

(a) Owners or operators of Class

VI wells must demonstrate to the
satisfaction of the Director that the wells

will be sited in areas with a suitable geologic system. The geologic system must be comprised of:

(1) An injection zone of sufficient areal extent, thickness, porosity, and permeability to receive the total anticipated volume of the carbon dioxide

stream ;

(2) A confining zone(s) that is

free of transmissive faults or fractures and of sufficient areal extent and integrity to contain the injected carbon dioxide stream and displaced formation fluids and allow injection at proposed maximum pressures and volu mes without initiating or propagating fractures in the confining zone(s); and (2) A confining zone(s) that is laterally continuous

and free of known transecting, transmissive faults

or fractures and of sufficient areal extent and integrity to cont ain the injected carbon dioxide stream and displaced formation fluids and allow injection at proposed maximum pressures and volumes without initiating or propagating fractures in the confining zone(s); and over an area sufficient to prevent the movement of injected or displaced fluids into a USDW; The proposed clarification keeps the emphasis on the non

- endangerment of USDWs and limits the requirements to that which is known or can be readily determined.

(b) At the Director‘s discretion,

owners or operators of Class VI wells must identify and characterize additional zones that will impede vertical fluid movement, are free of faults and fractures that may interfere with containment, allow for pressure dissipation, and provide additional opportunit ies for monitoring, mitigation

and remediation. (b) At the Director‘s discretion, owners or operators of Class VI wells must identify and characterize additional zones that will impede vertical fluid movement, are free of faults and fractures that may inte rfere with containment, allow for pressure dissipation, and provide additional opportunities for monitoring, mitigation

and remediation. This paragraph creates a presumption that

additional confining zones WILL be required.

It is also redundant given the previous

sections.

146.84 146.84. Area of review and corrective

action

(a) The area of review is the region surrounding the geologic sequestration project that may be impacted by the injection activity. The area of review is based on computational

mo deling that accounts for the physical and chemical properties of all phases of (a) The area of review is the region surrounding the geologic sequestration project that may be impacted by the injection activity. The area of

review is based on computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon

dioxide stream. the subsurface three

- dimensional extent of the carbon dioxide plume, associated pressure front, as wel l as the overlying

formations and surface area above that Edits make this provision consistent with the

defin ition of ―Area of R eview‖ , which was revised.December 2 3 , 2008

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Provision EPA Proposal API Comments Rationale

the injected carbon dioxide stream. delineated region.

(b) The owner or operator of a Class VI well must prepare, maintain, and comp ly with a plan to delineate the area of review for a proposed geologic sequestration project, periodically reevaluate the delineation, and perform

corrective action that meets the requirements of this section and is acceptable to the Director. As a part o f the permit application for approval by the Director, the owner or operator must

submit an area of review and corrective action plan that includes the following

information:

(1) The method for delineating

the area of review that meets the requirements of paragraph (c) of this section, including the model to be used, assumptions that will be made, and the

site characterization data on which the model will be based; (b) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan to delineate the area of review for a proposed geologic sequestration project, periodically reevaluate the delineation, and perform corrective action that meets the requirements of

this section and is in a manner and at a frequency acceptable to the Direct or. As a part of the permit application, for approval by the

Director the owner or operator must submit an area of review and corrective action plan that includes the following information: Clarification.

146.84(b)(2) (2) A description of:

(i) The mini mum fixed frequency, not to exceed 10 years, the owner or operator proposes to reevaluate the area of review;

(ii) The monitoring and operational conditions that would warrant a reevaluation of the area of review prior

to the next scheduled reevaluation a s determined by the minimum fixed frequency established in paragraph (b)(2)(i) of this section.

(iii) How monitoring and operational data (e.g., injection rate and pressure) will be used to inform an area (i) The minimum fixe d frequency, not to exceed 10 years, the owner or operator proposes to reevaluate the area of review;

(ii) The monitoring and operational

conditions that would warrant a reevaluation of the area of review prior to the next scheduled

reevaluation as determ ined by the minimum fixed frequency established in paragraph (b)(2)(i) of

this section.

( iii) (i) How monitoring and operational data (e.g., injection rate and pressure) will be used to inform an area of review reevaluation; andDecember 2 3 , 2008

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Provision EPA Proposal API Comments Rationale

of review reevaluation; and

(iv) How corrective act ion will be conducted to meet the requirements of paragraph (d) of this section, including what corrective action will be performed prior to injection and what, if any, portions of the area of review will have corrective action addressed on a phased

basis and how the phasing will be determined; how corrective action will be adjusted if there are changes in the area of review; and how site access will be guaranteed for future corrective action. ( iv ii ) How corrective action will be conducted to meet the requ irements of paragraph (d) of this section, including what corrective action will be performed prior to injection and what, if any, portions of the area of review will have corrective action addressed on a phased basis and how the phasing will be determined ; how corrective action will be adjusted if there are changes in the area of review; and how site access will be guaranteed arranged for future corrective action. Future access cannot be guaranteed for an area in advance that may not even be within

the bou ndaries of the AOR/ project.

146.84(c) (c) Owners or operators of Class

VI wells must perform the following actions to delineate the area of review, identify all wells that require corrective action, and perform corrective action on

those wells:

(1) Pre dict, using computational modeling, the projected lateral and vertical migration of the carbon dioxide plume and formation fluids in the

subsurface from the commencement of injection activities until the plume movement ceases, pressure differentials

suffic ient to cause the movement of injected fluids or formation fluids into a USDW are no longer present, or after a fixed time period as determined by the

Director. The model must: (1) Predict, using computational modeling, the projected lateral and vert ical migration of the carbon dioxide plume and formation fluids in the subsurface from the commencement of injection activities until the plume movement ceases, pressure differentials sufficient to cause the movement of injected fluids or formation fluids into a USDW are no longer present, or after for a fixed time period as determined by the Director.

The model modeling must: Clarification

146.84(c)(i) (i) Be based on detailed geologic

data collected to characterize the injection zone, confining zon e and any additional zones; and anticipated operating data, including injection pressures, rates and total volumes over (i) Be based on detailed geologic data collected

available to characterize the injection zone, confining zone and any add itional zones ; and anticipated operating data, including injection pressures, rates and total volumes over the proposed life of the geological sequestration Allows the use of all available data, not just data collected specifically for this permit.December 2 3 , 2008

20 Rule

Provision EPA Proposal API Comments Rationale

the proposed life of the geological sequestration project;

(ii) Take into account any geologic heterogeneities, data quality,

and their possible impact on model predictions; and

(iii) Consider potential migration through faults, fractures, and artificial penetrations. project the duration of injection;

(ii) Take into account any relevant geologic heterogeneities, an d data quality, and their possible impact on model predictions; and

(2) Using methods approved by the Director, identify all penetrations, including active and abandoned wells and underground mines, in the area of review that may penetrate the confining zone. Provide a description of each well‘s type, construction, date drilled, location, depth, record of plugging and/or completion, and any additional

informatio n the Director may require; and

. (2) Using methods approved by the Director,

I dentify all known artificial penetrations into the confining zone available in the public record

, including active and abandoned wells and underground mines, in the area of revi ew that

may penetrate reach the confining zone. Provide a description of each well‘s type, construction, date drilled, location, depth, record of plugging and/or completion, and any additional information the Director may require; and Changed for consisten cy with earlier language.

(3) Determine which abandoned

wells in the area of review have been plugged (as required by § 146.92) in a manner that prevents the movement of

carbon dioxide or associated fluids that may endanger USDWs (3) Determine which aba ndoned wells identified in 146.84 (c) (2) in the area of review have been plugged (as required by §146.92) in a manner that prevents the movement of carbon dioxide or

associated formation fluids that may endanger
USDWs. Remove as redundant.

146.84(d) (d ) Owners or operators of Class

VI wells must perform corrective action

on all wells in the area of review that are

determined to need corrective action using methods necessary to prevent the

movement of fluid into or between USDWs including use of corrosio n resistant materials, where appropriate. (d) Owners or operators of Class VI wells must perform corrective action using materials suitable

for use with the carbon dioxide stream and formation fluids, on all wells in the area of review

identified in 146. 84(c)(2) that are determined to

need corrective action‖. using methods necessary to prevent the movement of fluid into or between USDWs including use of corrosion resistant materials, where appropriate. Experience with CO2 based EOR strongly supports the u se of many conventional materials that might not meet the technical
definition of ―corrosion resistant‖.December 2 3 , 2008

21 Rule

Provision EPA Proposal API Comments Rationale

(e) If monitoring data indicate an endangerment to USDWs, the owner or operator must notify the Director and cease operations as required by §

146.9 4. (e) If monitoring data indicate an endangerment to USDWs, the owner or operator must notify the Director and cease operations as required by §

146.94. T his is not needed since § 146.94 already specifies the notifica tion and cessation of injection. API s uggests the removal of this language as unnecessarily duplicative.

(f) At the minimum fixed frequency, not to exceed 10 years, as specified in the area of review and corrective action plan, or when monitoring and operational conditions
warrant, owners o r operators must:

(1) Reevaluate the area of review in the same manner specified in paragraph (c)(1) of this section;

(2) Identify all wells in the reevaluated area of review that require

corrective action in the same manner specified in paragraph (c)(2) of this section; (f) At the minimum fixed frequency, not to exceed 10 years, a s specified in the approved area of review and corrective action plan, or W hen monitoring and operational conditions warrant, owners or operators must: Rather than a fixed time period, API recommends following a performance based approach that would be based on significant changes in injection parameters or anomalous monitoring results.

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

reevaluate d area of review in the same manner specified in paragraph (c)(3) of this section; and

(4) Submit an amended area of review and corrective action plan or demonstrate to the Director through monitoring data and modeling results

that no amendment to the are a of review and corrective action plan is needed. ( 4) Submit an amended area of review and corrective action plan or demonstrate to the Director through monitoring data and modeling

results that no amendment change to the area of

review and correctiv e action plan is needed. Clarification.

146.84(g) (g) The emergency and remedial

response plan (as required by § 146.94)

and a demonstration of financial responsibility (as described by § 146.85)

must account for the entire area of review, regardles s of whether or not

corrective action in the area of review is phased.December 2 3 , 2008

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146.85 146.85 Financial responsibility

(a) The owner or operator must

demonstrate and maintain financial responsibility and resources for corrective action (that meets the requireme nts of § 146.84), injection well plugging (that meets the requirements of § 146.92), post

- injection site care and site closure (that meets the requirements of § 146.93), and emergency and remedial response (that meets the requirements of § 146.94) in a man ner prescribed by the

Director until:

(1) The Director receives and approves the completed post

- injection site care and site closure plan; and

(2) The Director determines that the site has reached the end of the post

injection site care period. (1) The Director receives well plugging report identified in 146.92(d) and approves or completion of the completed post

- injection site care and site closure plan as appropriate ; and Maintenance of the well plugging financial obligation until si te closure is not necessary. The Director should have the authority to release the obligation once the well is plugged.

(b) The owner or operator must provide to the Director, at a frequency determined by the Director, written updates of adjustments t o the cost estimate to account for any amendments

to the area of review and corrective action plan (§ 146.84), the injection well plugging plan (§ 146.92), and the post

injection site care and site closure plan (§ 146.93). (b) The owner or operator must pr ovide to the Director, at a frequency determined by the Director, but no more than annually , written updates of adjustments to the cost estimate to account for any amendments change to the area of review and corrective action plan (§146.84), the injection well plugging plan (§146.92), and the post

- injection site care and site closure plan (§146.93). Updates more frequent than annual is not justified.

146.85(c) (c) The owner or operator must

notify the Director of adverse financial

conditions such as bankr uptcy, that may affect the ability to carry out injection well plugging and post

- injection site care and

site closure. (c) The owner or operator must notify the Director

of adverse financial conditions such as bankruptcy

, that may affect the ability to ca rry out injection well plugging and post

- injection site

care and site closure. Clarification.

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

Director if the Director has reason to (d) The operator must provide an adjustment of

the cost estimate to the Director if the Director

h as reason to believe that original the most Clarification.December 2 3 , 2008

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believe that the original demonstration is

no lo nger adequate to cover the cost of injection well plugging (as required by § 146.92) and post

- injection site care and site closure (as required by § 146.93). recent demonstration is no longer adequate to cover the cost of injection well plugging (as required by §146.92) and post

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

146.86 6. I njection well construction

requirements

(a) General. The owner or operator must ensure that all Class VI wells are constructed and completed to:

(1) Prevent the movement of fluids into or between USDWs or into any unauthorized zones;

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

(3) Permit continuous monitoring of the annulus space between the injection tubing and long string casing. (1) Prevent the movement of fluid into or between USDWs or into any unauthorized zones;

cont aining any contaminant into USDWs , if the presence of that contaminant may cause a violation of any primary drinking water regulation under 40 CFR part 142 or may otherwise adversely affect the health of persons.; The proposed changes reflect the non

enda ngerment standard that is the basis of the UIC program.

(b) Casing and Cementing of

Class VI Wells.

(1) Casing and cement or other

materials used in the construction of
each Class VI well must have sufficient structural strength and be designed for

the life of the geologic sequestration project. All well materials must be compatible with fluids with which the materials may be expected to come into

contact and meet or exceed standards developed for such materials by the American Petroleum Institute, AST M International, or comparable standards acceptable to the Director. The casing and cementing program must be designed to prevent the movement of
fluids into or between USDWs. In order

to allow the Director to determine and specify casing and cementing

r equirements, the owner or operator must provide the following information: (1) Casing and cement or other materials used in

the construction of each Class VI well must have sufficient structural strength and be designed for the operating life of the geolog ic sequestration project well . All well materials must be compatible suitable for use with the fluids with which the materials may be expected to come

into contact and meet or exceed test standards or practices developed for such materials by the

American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. The casing and cementing program must be designed to prevent

the movement of fluids into or between USDWs

. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following

information: The life of a g eologic sequestration project

could be different than the life of the well. Class VI well design should be based on the

life of the well.December 2 3 , 2008

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146 .86(b)(1) (i) Depth to the injection zone;

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

(iii) Hole size;

(iv) Size and grade of all casing strings (wall thickness, external diameter, nominal weight, length, joint spe cification and construction material);

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

(vi) Down

- hole temperatures;

(vii) Lithology of injection and confining zones; (v ) Corrosiveness Composition of the

carbon dioxide strea m and formation fluids;

(vi) Down

- hole temperatures and

pressures; There is no method for measurement of
―corrosiveness‖ of a CO2 stream. The relevant information is the composition of the
CO2 stream.

Technical clarification

(viii) Type o r grade of cement;

and

(ix) Quantity, chemical composition, and temperature of the

carbon dioxide stream. (viii) Type or grade of cement and additives ; and Technical clarification.

(2) Surface casing must extend through the base of the lowermost
USDW and be cemented to the surface. (2) Surface casing must extend through the base

of the lowermost USDW above the injection zone

and be cemented to the surface. In some parts of the US the USDW is very deep and this standard may preclude geologic sequestrat ion in these areas.

(3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages. (3) At least one long string casing, using a

sufficient number of centralizers set in a manner

so as to create a cement bond through the injection and confining zone(s)

. The long string casing must extend to the injection zone and

must be cemented isolated by circulating cement

to the surfac e in one or more stages. placing cement and/or other isolation technologies as necessary to provide adequate isolation of the injection zone and provide for protection of Cementing to surface i s not necessary to protect USDWs , and may have negative consequences, as follows. Cement to surface would eliminate the ability to monitor pressures in this annulus and would limit flexibility of remedial options. As revised, the proposal would allow for application and development of alternative technologies. See API RP90 for description of risk

- based approach for managing situations involvingDecember 2 3 , 2008

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Provision EPA Proposal API Comments Rationale

USDWs

. annular casing pressure. Industry experience
with CO2 EOR under the C lass II program demonstrates the effectiveness of existing cementing procedures.

146.86(b) (4) C irculation of cement may be

accomplished by staging. The Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the

cement does not allow fluid movement

behind the well bore. (4) Circulation of cement may be accomplished by staging. The Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the cement does not allow fluid

movement behind the well bore. Same as above

(5) Cement and cement additives must be compatible with the
carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the geologic sequestration project. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of

chann els to ensure that USDWs are not endangered. (5) Cement and cement additives must be compatible suitable for use with the carbon
dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity

over the design operating life of the geologic sequestration project well. 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. Experie nce with CO2 EOR under the C lass II program demonstrates the effectiveness of existing cementing materials and procedures.
Standard API cements have been used in numerous CO2 EOR operations with no adverse consequences. Refer to the citations

within EPA‘ s proposed rule 73 FR 43532

- 43533: Carey et al., (2007), Crow et al., (2008), and Meyer, J.P (2007)

.

146.86(c) (c) Tubing and packer.

(1) All owner and operators of Class VI wells must inject fluids through tubing with a packer set at a depth opposite a cemented interval at the location approved by the Director.

(2) In order for the Director to determine and specify requirements for tubing and packer, the owner or operator must submit the following information:

(i) Depth of setting;

(ii) Characteris tics of the carbon (ii) Composition of the carbon dioxide stream. There is no method for measurement ofDecember 2 3 , 2008

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dioxide stream (chemical content, corrosiveness, temperature, and density); (chemical content, corrosiveness, temperature, and density); ―corrosiveness‖ of a CO2 stream. The

relevant information is the composition, not characteristics, of the CO2 stream. T he composition of the CO2 stream is more relevant to the design of a tubing and packer system.

146.86(c)(2) (iii) Injection pre ssure;

(iv) Annular pressure;

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

(vi) Size of casing; and

(vii) Tubing tensile, burst, and collapse strengths. (iii) Maximum proposed Injection temperature and pres sure;

(iv) Maximum proposed Annular

pressure;

(v) Maximum proposed Injection rate (intermittent or continuous) and volume of the carbon dioxide stream; Technical corrections.

146.87 7. Logging, sampling, and testing prior

to injection well operation

(a) During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any format ion fluids in, all relevant geologic formations to assure conformance with the injection well construction requirements under § 146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must s ubmit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, such logs and tests must include: (a) During the drilling and construction of a Class

V I injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic

formations to ass ure evaluate conformance with the injection well construction requirements under §146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prep ared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, such logs

and tests must include: The Director may require such logs and tests as may be needed after taking into account the availabil ity of similar data in the area of the drilling site, the construction plan, and the need for additional information that may arise from time to time as the construction of the well progresses and these may include the following: Obtaining the geologic inf ormation will not

assure conformance with well construction requirements, just measure or evaluate it.

In well defined areas, these evaluations are frequently unnecessary. The D irector should have discretion to select the appropriate requirements necessa ry to obtain sufficient baseline data and information. For example, in an area where a number of wells are being drilled, the logging of surface hole yields little

useful additional information. In particular, this change would allow the

Director to reduc e the requirements when multiple wells are installed for a project.December 2 3 , 2008

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(1) Deviation checks during drilling on all holes constructed by drilling a pilot hole which are enlarged by reaming or another method. Such checks must be at sufficiently frequent

int ervals to determine the location of the

borehole and to assure that vertical

avenues for fluid movement in the form of diverging holes are not created during drilling; and

146.87(a) (2) Before and upon installation

of the surface casing:

(i) Resi stivity, spontaneous potential, and caliper logs before the casing is installed; and (i) Resistivity, spontaneous potential, and caliper logs before the casing is installed; and After a few wells are drilled in an area, these evaluations are frequently u nnecessary and yield little new information. This is an example of where Director discretion may be appropriate.

(ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented. (ii) A Cement bond and variable de nsity log, and a temperature log evaluation log(s) after the casing is set and cemented. Unusual to run these logs in a surface hole due to uniformity of shallow geology. This is an example of where Director discretion may be appropriate.

The proposed chan ge provides more flexibility to select the appropriate log to demonstrate adequate cement bond.

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

(i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any other logs the Director requires for the given geology before the casing is installed;

and Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs and any other logs the Director requires based on site specific cond itions and risk

- based factors for the given geology before the casing is installed; and It is a cceptable to specify basic logging requirements, however, special logs should not be specified. Any other information from

the area should be used instead

.

( ii) A cement bond and variable density log, and a temperature log after (ii) A Cement bond and variable density log, and a temperature log evaluation log(s) after the The proposed change p rovides more flexibility to select the appropriate log to demonstrateDecember 2 3 , 2008

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the casing is set and cemented. casing is set and cemented. adequate cement bond.

146.87(a)(4) (4) A series of tests designed to

demonstrate the internal and external mechanical integrity of injection wells, which may include:

(i) A pressure test with liquid or

gas;

(ii) A tracer survey such as

oxygen

- activation logging;

(iii) A temperature or noise log;

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

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

and that are required of and/or approved of by the Director. (4) A series of tests Test(s) designed to

demonstrate the internal and external mechanical integrity of injection wells, which may

include:

(i) A pressure test with liquid or gas;

(ii) A tracer survey Dia gnostic tools such as

oxygen

- activation logging;

(iii) A temperature or noise log; and /or

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

(5) Any alternative methods that provide equivalent or better information and that are required of and /or approved of by the Director

. Technical and grammatical corrections

In (iv), ―if required by the Director‖ is unnecessary, as it is in subsection (a)

Same comment as above in (iv).

146.87(b) (b) The owner or operator must

take and submit to th e Director whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept cores from nearby wells if the owner or operator can

demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core other formations in the

borehole. (b) The owner or operator must submit to the

Director a report describing whole cores or

sidewall cores representative of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept data from cores and fluid samples from nearby wells if the owner or operator can

demonstrate that core retrieval is not possible

and that such cores data are representative of

conditions at the well in the wellbore

. The Director may require the owner or operator to

core other formations in the borehole. The information required should be sufficient to prope rly describe the injection and confining zones.

(c) The owner or operator must record the fluid temperature, pH, conductivity, reservoir pressure and the static fluid level of the injection zone(s). (c) Prior to injection well operation, the owner or

op erator must record provide representative

information on the fluid formation temperature,
formation fluid pH and conductivity, and reservoir

pressure and the static fluid level of the injection zone(s). Technical corrections. Reservoir pressure

and static fluid level are redundant parameters.

The phrase ―representative information‖ prevents the operator from having to do all

tests in all wells.December 2 3 , 2008

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(d) At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zone(s):

(1) Fracture pressure;

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

(3) Physical and chemical

characteristics of the formation fluids in the injection zone. (d) At a minimum , the owner or operator must determine or calculate the following information concerning the injection and confining zone(s):

(1) Fracture pressure;

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

(3) Physical a nd chemical characteristics of the formation fluids in the injection zone. With the exception of calculating fracture pressure, the requirements of this section appear redundant to other requirements of prior sections. The fracture pressure requirement ha s been added to section 146.87(e) below.

(2) and (3) are too vague.

(e) Upon completion, but prior to operation, the owner or operator must conduct the following tests to verify hydrogeologic characteristics of the injection zone:

(1) A pump test; or

(2) Injectivity tests. (e) ( d ) Upon completion but P rior to injection

well operation, the owner or operator must

conduct the following tests to verify hydrogeologic characteristics of the injection

zone:

(1) A pump test; or

(2) Injectivity tests.

est imate fracture pressures of the injection and confining zones and injectivity of the injection

zone. Estimates should be based on representative hydrogeologic and geomechanical characteristics of the injection zone

. Allows the use of information such as leak off tests conducted during the drilling operation.

T he results of a pump test ( pumping fluid from the well) have no relevance for an injection

well.

Deletion of the injectivity test would allow the

use of non

- destructive methods to calculate

fractur e pressure.

146.87(f) (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 conductin g the first test and submit any changes to the schedule 30 days prior to the next

scheduled test. (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 upon spudding the wel l

and notify the Director of submit any changes to

the schedule 30 days 48 hours prior to the next
scheduled test. The changes reflect the realit ies of flexible rig

schedules and operations . In addition, they are fully consistent with current Class II requirements and practices which deal with these issues on a daily basis

.

146.88 Injection well operating requirements

(a) Except during stimulati on, the owner or operator must ensure that injection pressure does not exceed 90 percent of the fracture pressure of the injection zone so as to assure that the ( a) Except during stimulation, the owner or operator must ensure that injection pressure

does no t exceed 90 percent of the fracture pressure of the injection zone so as to assure that the injection does not initiate new fractures or propagate existing fractures in the injection zone. In no case may injection pressure initiate API is conce rned about three aspects of proposed section 146.88(a), governing injection pressure limitations. First, it ―restricts‖ fractures in the injection zone ―except during stimulation‖ rather than focusing on maintaining the integrity of the confining zone, wh ich is what really mattersDecember 2 3 , 2008

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Provision EPA Proposal API Comments Rationale

injection does not initiate new fractures or propagate existing fractures in the injection zone . In no case may injection pressure initiate fractures in the confining zone(s) or cause the movement of injection or formation fluids that endangers a USDW. fractures in the confin ing zone(s) or cause the movement of injection or formation fluids that endangers a USDW.

(a) The owner or operator must comply with a maximum injection pressure limit approved by the Director and specified in the permit. In approving a maximum injection pressure limit,

the Director shall consider the results of well tests and, where appropriate, geomechanical or
other studies that assess the risks of tensile

failure and shear failure. The Director shall approve limits that, with a reasonable degree of

cer tainty, will avoid initiation or propagation of fractures in the confining zone or cause

otherwise non

- transmissive faults transecting the confining zone to become transmissive. In no case may injection pressure cause movement of injection or formation flu ids in a manner prohibited by 40 CFR Part 144.12(a) for protecting USDWs. Second, it fails to refer specifically to the full range of potential geomechanical failure modes potentially posed by operations at a particular site. Third, the type of geomechanical risk that is

address ed (initiation or propagation of fractures), is dealt with in a potentially arbitrary fashion (the 90% of fracture pressure limit), which may not be appropriate in all

cases.

The MSDG ‘ s recommended language addresses these concerns by focusing on maintaining the integrity of the confining zone and including tensile failure and shear failure as transmissivity concerns. It calls for additional geomechanical studies of tensile failure and shear failure only ―where appropriate‖ because there will be locations

whe re experience or existing information will provide sufficient evidence to avoid the need

for additional studies. The need for conducting additional tests and for determining which tests would be acceptable
is left to the Director‘s discretion.

(b) Injection between the outer

most casing protecting USDWs and the well bore is prohibited. (b) Injection of the CO2 strea m between the outermost casing protecting USDWs and the well bore is prohibited. Routine injection into zones other than the target interval(s) should be prohibited, however, wording of this requirement is not clear as to which interval is being addressed

. An absolute prohibition on injection into this

annulus may also limit diagnostic options that
could be useful.December 2 3 , 2008

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

corrosive fluid approved by the Director. The owner or operator must maintain on the annulus a pressure that exceeds the operating injection pressure, unless the

Director determines that such requirement might harm the integrity of

the well. (c) The owner or operator must fill the annul us between the tubing and the long string casing

with a non

- corrosive fluid approved by the

Director. The owner or operator must maintain on the annulus a pressure that exceeds the operating injection pressure, unless the Director determines that such req uirement might harm the integrity of the well. a positive pressure on the

annulus

. Industry experience with the Class II UIC program does not support this requirement.

Positive annular pressure that exceeds the operating injection pressure is not necessar y because a leak from tubing to annulus does not have the same implications as in a Class I

hazardous situation.

146.88(d) (d) Other than during periods of

well workover (maintenance) approved by the Director in which the sealed tubing

- casing annulus is of necessity

disassembled for maintenance or corrective procedures, the owner or operator must maintain mechanical integrity of the injection well at all times.December 2 3 , 2008

32 Rule

Provision EPA Proposal API Comments Rationale

146.88 (e) The owner or operator must

install and use continuous recording

devices to moni tor: The injection pressure; the rate, volume, and temperature of the carbon dioxide stream; and the pressure on the annulus between the tubing and the long string casing and annulus fluid volume; and

must install and use alarms and

automatic down

- hole sh ut

- 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; (e ) The owner or operator must install and use continuous recording devices to monitor: the injection pressure; the rate, volume, and temperature of the carbon dioxide stream and

. The owner or operator must regularly monitor the pressure on the annulus betw een the tubing and the long string casing and annulus fluid volume

and

. The owner or operator must install and use

alarms and automatic down

- hole shut

- off systems, designed to alert the operator and shut

in the well when operating parameters such as injec tion rate, injection pressure, or other parameters approved by the Director diverge beyond ranges and/or gradients specified in the permit; Over

- pressure protection is best achieved by ensuring compatibility of the casing/tubing material design strength w ith the surface injection (compression) system. Down

- hole

shut

- in devices are not appropriate for this application. These devises are installed in the tubing string and are typically near the surface of the well. They‘re intended to seal the tubing in th e event of catastrophic failure of the wellhead. These devises would provide little if any protection to USDWs. Is not practicable to install these devises deep within the well (e.g. shortly above the packer). Additionally these devises create a restric tion on running other tools like logging tools in the well and therefore could limit an operators ability to do required monitoring and diagnostic work. Lastly, these devises require periodic testing and maintenance which could require either pulling the devi c e by wireline or by pulling the entire tubing string depending on the type of devi c e installed. Either of these activities would be disruptive and costly to the overall project operations.

A more appropriate approach would be installation of landing nipples at appropriate points in the tubing string which would allow use of wireline retrievable plugs when

needed.

146.88 (f) If a down

- hole automatic

shutdown is triggered or a loss of mechanical integrity is discovered, the owner or operator must im mediately investigate and identify as expeditiously as possible the cause of the shutoff. If, upon such investigation, the well appears to be lacking mechanical integrity, or if monitoring required under paragraph (e)

of this section otherwise indicates t hat the well may be lacking mechanical (f) If a n down

- hole automatic shutdown is triggered or a loss of mechanical integrity is discovered, the owner or operator must immediately investigate and identify as expeditiou sly as possible the cause of the

shutoff . If, upon such investigation, the well appears to be lacking mechanical integrity, or if monitoring required under paragraph (e) of this section otherwise indicates that the well may be lacking mechanical integrity, the owner or operator must: Technical clarification given changes above.December 2 3 , 2008

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Provision EPA Proposal API Comments Rationale

integrity, the owner or operator must:

146.88(f) (1) Immediately cease injection;

(2) Take all steps reasonably necessary to determine whether there may have been a release of the injected

carbon dioxide stream into a ny unauthorized zone;

(3) Notify the Director within 24 hours;

(4) Restore and demonstrate mechanical integrity to the satisfaction of the Director prior to resuming injection;

and

(5) Notify the Director when injection can be expected to resume. (3) No tify the Director within 24 hours of discovery ;

146.89 9. Mechanical integrity

(a) A Class VI well has mechanical integrity if:

(1) There is no significant leak in the casing, tubing or packer; and

(2) There is no significant fluid

movement into a USDW through channels adjacent to the injection well

bore.

(b) To evaluate the absence of significant leaks under paragraph (a)(1) of this section, owners or operators must, following an initial annulus pressure test, continuously monitor injection p ressure, rate, injected volumes, and pressure on the annulus between tubing and long stem casing and annulus fluid volume as specified in § 146.88(e); (b) To evaluate the absence of significant leaks under paragraph (a)(1) of this section, owners or
operat ors must, following an initial annulus

pressure test, continuously monitor and record at least daily , annulus pressure and volumes of packer fluid injected or removed from injection pressure, rate, injected volumes, and pressure

on the annulus between the tubing and long stem

st ring casing and annulus fluid volume as specified in §146.88 (e); Technical clarification.December 2 3 , 2008

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146.89(c) (c) At least once per year, the

owner or operator must use one of the following methods to determine the absence of significant fluid movement under paragraph (a)(2) of this section:

(1) A tracer survey such as

oxygen

- activation logging;

(2) A temperature or noise log;

or

(3) A casing inspection log, if required by the Director. (c) At least once per year, the owner or operator must confirm the absence of significant fluid movement under paragraph (a)(2) of this section using a method acceptable to the Director (e.g. including diagnostic surveys such as oxygen

activation logging or temperature or noise logs).

(1) A tracer survey such as oxygen

- activation logging;

(2) A temperature or noise log; or

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

Director. Revised text supports a performance

- based approach and allows the development and use of new technologies as they become

availa ble. Cement circulation to the surface is not necessary because having the open annulus above the top of cement allows regular monitoring of annular pressure which could indicate leakage.

Subsection ( 3 ) was deleted because i t requires the tubing to be pull ed at significant

cost and risk of uncontrolled releases.

(d) The Director may require any

other test to evaluate mechanical integrity under paragraph (a)(1) or (a)(2) of this section. Also, the Director may

allow the use of a test to demonstrate

mecha nical integrity other than those listed above with the written approval of the Administrator. To obtain approval,

the Director must submit a written request to the Administrator, which must set forth the proposed test and all technical data supporting its use. The Administrator must approve the request if it will reliably demonstrate the mechanical integrity of wells for which its use is proposed. Any alternate method approved by the Administrator will be published in the Federal Register and may be used in all States in accordance with applicable State law unless its use is restricted at the time of approval by the

Administrator.December 2 3 , 2008

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146.89(e) (e) In conducting and evaluating

the tests enumerated in this section or others to be allowed by the Director, t he owner or operator and the Director must apply methods and standards generally accepted in the industry. When the owner or operator reports the results of mechanical integrity tests to the Director, he/she shall include a description of the test(s) and the method(s) used. In making his/her evaluation, the Director must review monitoring and other test data submitted since the previous

evaluation.

(f) The Director may require

additional or alternative tests if the results presented by the owner or

o perator under paragraph (d) of this section are not satisfactory to the

Director to demonstrate that there is no significant leak in the casing, tubing or packer or significant movement of fluid into or between USDWs resulting from the injection activity a s stated in paragraphs (a)(1) and (2) of this section.

146.90 Testing and monitoring requirements

The owner or operator of a Class VI well must prepare, maintain, and comply with a testing and monitoring plan to verify that the geologic sequestration pr oject is operating as permitted and is not endangering USDWs. The testing and monitoring plan must be submitted with the permit application, for Director approval, and must include a description of how the owner or operator will meet the requirements of t his section. Testing and monitoring associated with geologic sequestration projects must, at a minimum, include:December 2 3 , 2008

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146.90 (a) Analysis of the carbon

dioxide stream with sufficient frequency to yield data representative of its chemical and physical cha racteristics;

(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; (b) Installation and use, except during well workovers as defined in §146.8 8 (d), of

continuous recording monitoring devices (including digital devices capturing periodic data) to monitor injection pressure, rate and volume;

and r ecord at least daily the pressure on the annulus between the tubing and the long string casing; and the annulus fluid volume ; §146.86(d) does not exist; perhaps §146.88(d) is what was apparently intended.

There is concern regarding what constitutes

contin uous monitoring. Industry agrees that regular monitoring of the parameters identified by EPA is appropriate. Our experience with CO2 EOR strongly shows that daily monitoring of most of these parameters is adequate (exceptions to this would be on a

site

- sp ecific basis). Recording should generally be done on a daily basis and reporting on a semi

- annually basis.

146.90 (c) Corrosion monitoring of the

well materials for loss of mass, thickness, cracking, pitting and other signs of corrosion must be perform ed on a quarterly basis to ensure that the well components meet the minimum standards for material strength and performance set forth in § 146.86(b) by: (c) Where conditions warrant , corrosion monitoring of the well materials for loss of mass, thickness, c racking, pitting and other signs of corrosion must be performed on a and recorded

at least quarterly basis which may be modified to be less frequent as approved by the Director based on construction materials, operating conditions, and monitoring history t o ensure that the well components meet the minimum standards for material strength and performance set forth in §146.86(b) by: Technical correction.

API questions the need for corrosion monitoring of most injected CO2 streams since they will typically be nearly pure and dry thus having no corrosive properties. Industry experience with production, transportation, and injection of dry CO2 strongly illustrates

the non

- corrosive nature of this type of CO2

stream.

146.90(c) (1) Placing coupons of the well

co nstruction materials in contact with the carbon dioxide stream; or

(2) Routing the carbon dioxide stream through a loop constructed with the material used in the well; or

(3) Using an alternative method approved by the Director; (1) Placing Analyzing cou pons of the well

construction materials placed 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 and inspecting the materials in the loop ; or

(3) Using an alt ernative method, materials, or time period approved by the Director; Clarifying edits.December 2 3 , 2008

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146.90(d) (d) Periodic monitoring of the

ground water quality and geochemical changes above the confining zone(s) that may be a result of carbon dioxide

movement thro ugh the confining zone or

additional identified zones:

(1) The location and number of monitoring wells must be based on specific information about the geologic sequestration project, including injection rate and volume, geology, the presence

of artificial penetrations and other factors;

(2) The monitoring frequency and spatial distribution of monitoring

wells must be based on baseline geochemical data that has been collected under § 146.82(a)(6) and any modeling results in the area of review

evaluation re quired by § 146.84(b); (d) Periodic monitoring of the ground water

formation fluid quality and geochemical changes

above in a permeable and porous formation as near as practicable to the confining zone(s) for geochemical changes that may be a result of

car bon dioxide or displaced formation fluid

movement through the confining zone or

additional identified zones :

(1) The location and number of monitoring wells must be based on specific information about the geologic sequestration project, including injection rate and volume, geology, the presence of artificial penetrations and other relevant factors as warranted by a risk

- assessment;

(2) The monitoring frequency and spatial distribution of monitoring wells must be based on geological, geochemical and geophysi cal data

that has been collected under § 146.82(a)(6) §146.82(d) and any modeling results in the area of review evaluation required by §146.84(b); Drilling monitoring wells should be carefully

considered since each well introduces a potential pathway for movement. In addition the cost of adding multiple wells could create a barrier to CCS development, while providing

limited information on actual movement of the
CO2 stream.

146.90 (e) A demonstration of external

mechanical integrity pursuant to §

146.8 9(c) at least once per year throughout the duration of the geologic sequestration project;

(f) A pressure fall

- off test at least once every five years unless more frequent testing is required by the Director based on site specific information; (e) A demo nstration of external mechanical integrity pursuant to §146.89(c) at least once per

year until the well is plugged ;

(f) If conditions warrant, A pressure fall

- off test or other equivalent test that identifies reservoir conditions with respect to flow dyna mics at least once every five years unless more frequent testing is required by the Director based on site specific information; Technical clarifications.

(g) Testing and monitoring to

track the extent of the carbon dioxide plume and the position of the pressure front by either monitoring for pressure changes in the first formation overlying the confining zone or using indirect, geophysical techniques (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down

- hole carbon dioxide

detectio n tools); (g) Testing and monitoring as appropriate to support the model for to track ing the extent of the carbon dioxide plume and the position of the pressure front. by either monitoring for pressure changes in the first formation overlying the confining zone or using indirect, geophysical techniques (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down

- hole carbon dioxide detection tools); Monitoring outside of the injection zone provides little information of value for tracking

and monitoring the injected plume. Examples

of how to test and monitor could be included

in the Preamble but need not be included in

the rule itself.December 2 3 , 2008

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146.90 (h) At the Director‘s discretion,

surface air monitoring and/or soil gas monitoring to detect movem ent of carbon dioxide that could endanger a USDW. (h) At the Director‘s discretion based on site

specific conditions and risk

- based factors

, surface air monitoring and/or soil gas monitoring

to detect movement of carbon dioxide that could endanger a USDW. In most situations soil and air monitoring does not provide an effective method of protecting
USDWs.

146.90(h) (1) The testing and monitoring

plan must be based on potential vulnerabilities within the area of review;

(2) The monitoring frequency

and s patial distribution of surface air monitoring and/or soil gas monitoring

must reflect baseline data and the monitoring plan must include how the proposed monitoring will yield useful

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

stan dards under 40 CFR 144.12; (1) The testing and monitoring plan must be

based on potential vulnerabilities site

- specific geologic factors, modeling, and risk

- assessment within the area of review; Technical clarification

146.90(i) (i) Any additional monit oring, as

required by the Director, necessary to support, upgrade, and improve computational modeling of the area of review evaluation required under § 146.84(b) and to determine compliance with standards under 40 CFR 144.12;

and

(j) A quality assurance a nd surveillance plan for all testing and monitoring requirements. (i) Any additional monitoring, as required by the Director, based on site

- specific conditions and

risk

- based factors, necessary to support, upgrade, and improve computational modeling of

the area of review evaluation required under § 146.84(b) and to determine compliance with
standards under 40 CFR 144.12 Technical clarification

146.91 11. Reporting requirements.

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

the Director, for each permitted Class VI

well:

(a) Semi

- annual reports containing:

(1) Any changes to the physical,

chemical and other relevant

characteristics of the carbon dioxide stream from the proposed operating (a) Semi

- annual or less frequent at the discretion

of the Director reports containing:

(1) Any significant changes to the physical,

chemical and other relevant characte ristics of the carbon dioxide stream from the proposed operating data; Over the life of the project, the Director may decide that less reporting is acceptable

(1) Technical clarification. Significance can be determined by a statistical analysis of the data. Rules should recognize that there willDecember 2 3 , 2008

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data;

(2) Monthly average, maximum

and minimum values for injection pressure, flow rate and volume, and annular pressure; be minor variations in many data sets over

time.

146.91(a) (3) A description of any event

that exceeds operating parameters for annulus pressure or injection pressure as specified in the permit;

(4) A de scription of any event which triggers a shutdown device required pursuant to § 146.88(e) and the response taken;

(5) The monthly volume of the carbon dioxide stream injected over the reporting period and project cumulatively;

(6) Monthly annulus fluid vo lume added; and

(7) The results of monitoring prescribed under § 146.90. (3) A description of any significant event that exceeds operating parameters for annulus pressure or injection pressure as specified in the permit;

(4) A description of any signific ant event which triggers a shutdown device required pursuant to §146.88(e) and the response taken; EPA should consider some significance threshold on reporting these events to avoid reporting events that would be of limited interest or consequence.

(b ) Report, within 30 days the

results of:

(1) Periodic tests of mechanical integrity;

(2) Any other test of the injection well conducted by the permittee if required by the Director; and

(3) Any well workover.

(c) Owners or operators must submit reports in an electronic format acceptable to the Director. At the discretion of the Director, other formats may be accepted.

146.92 12. Injection well plugging.

(a) Prior to the well plugging, the owner or operator must flush each Class VI injection well wi th a buffer fluid, (a) Prior to the well plugging, the owner or operator must flush each Class VI injection well with a buffer fluid, determine bottomhole reservoir pre ssure, and perform a final external mechanical integrity test of any relevant wellbore Many of the components that would be tested by an internal MIT are removed or tested during the plugging process.December 2 3 , 2008

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determine bottomhole reservoir pressure, and perform a final mechanical integrity

test. materials remaining.

146.92(b) (b) Well Plugging Pla n. The

owner or operator of a Class VI well must prepare, maintain, and comply with a plan that is acceptable to the Director. The requirement to maintain and implement an approved plan is directly enforceable regardless of whether the requirement is a c ondition of the permit. The well plugging plan must be submitted as part of the permit application and must include the following information:

(1) Appropriate test or measure

to determine bottomhole reservoir

pressure;

(2) Appropriate testing metho ds to ensure mechanical integrity as specified in § 146.89;

(3) The type and number of plugs to be used;

(4) The placement of each plug including the elevation of the top and bottom of each plug;

(5) The type and grade and quantity of material to be use d in plugging. The material must be compatible with the carbon dioxide stream; and

(6) The method of placement of the plugs. (2) Appropriate testing methods to ensure final

external mechanical integrity as specified in §146.89 (c) ;

(5) The type and grade and quantity of material to be used in plugging. The material must be

suitable for use with the carbon dioxide stream;

and Many of the components that would be tested by an internal MIT are removed or tested during the plugging process.

(c) Notic e of intent to plug. The owner or operator must notify the Director at least 60 days before plugging of a well. At this time, if any changes have been made to the original well plugging plan, the owner or operator must also provide the revised wellDecember 2 3 , 2008

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plugg ing plan. At the discretion of the Director, a shorter notice period may be

allowed.

146.92(d) (d) Plugging report. Within 60

days after plugging or at the time of the

next semi

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

must subm it a plugging report to the

Director. If the semi

- annual report is due less than 15 days after completion of plugging, then the report must be submitted within 60 days after plugging. The report must be certified as accurate by the owner or operator and b y the person who performed the plugging operation (if other than the owner or operator.) (d) Plugging report. Within 60 days after plugging the owner or operator must submit a plugging report to the Director. If the semi

- annual report is

due less than 15 d ays after completion of plugging, then the report must be submitted within 60 days after plugging. The report must be certified as accurate by the owner or operator and by the person who performed the plugging operation (if other than the owner or operato r.) The proposed changes are suggested to simplify and clarify a provision that API believes is needlessly complicated.

146.93 13. Post

- injection site care and site

closure

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

- injection

site care and site closure that meets the requirements of paragraph (a)(2) of this section and is acceptable to the Director.

(1) The owner or operator must submit the post

- injection site care and site closure plan as a part of the permit application to be approved by the

Director. (1 ) The owner or operator must submit the post

injection site care and site closure plan as a part of the permit application to be approved by the

Director. shall continue to conduct monitori ng as specified in the Director

- approved post

- injection site care and site closure plan, pursuant to the performance based criteria described in 146.93(b)(3). Revisions here reflect changes to § 146.93(b)(3)

(2) The post

- injection site care

and site clo sure plan must include the following information:

(i) The pressure differential between pre

- injection and predicted post

- injection pressures in the injection

zone; (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 Revisions here reflect changes to § 146.93(b)(3)December 2 3 , 2008

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(ii) The predicted position of the carbon dioxide plume and associated pressure front at s ite closure as
demonstrated in the area of review evaluation required under § 146.84(b); site closure as demonstrated in the area of review evaluation required under § 146.84(b);

146.93(a)(2) (iii) A description of post

- injection

monitoring location, methods, and proposed frequency; and

(iv) A proposed schedule for submitting post

- injection site care monitoring results to the Director. (iii) A description of post

- injection monitoring location, methods, and proposed frequency; and

(iv) A proposed schedule for submitting post

- injection site care monitoring results to the

Director.

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

must either submit an amended post

injection site care and site closure plan or demonstrate to the Director through monitoring data and modeling results that no amendment to the plan is

needed.

(4) The owner or operator may modify and resubmit the post

- injectio n site care and site closure plan for the Director‘s approval within 30 days of such change. (4) At any time during the post

- injection site care phase, t he owner or operator may modify and resubmit the post

- injection site care and site closure plan for the Director‘s approval within 30 days of such change. Technical Clarification.

146.93(b) (b) The owner or operator shall

monitor the site following the cessation of injection to show the position of the carbon dioxide plume and pressure front

and demonstra te that USDWs are not being endangered.

(1) The owner or operator shall continue to conduct monitoring as specified in the Director

- approved post

injection site care and site closure plan for at least 50 years following the cessation of injection. At the Director‘s discretion, the monitoring will continue until the geologic sequestration project (b) The owner or operator shall monitor the site following the cessation of injection to show the position of the carbon dioxide plume and pressure front and demonstrate that USDWs are not being endangered.

(1) The owner or operator shall continue to conduct monitoring as specified in the Director

approved post

- injection site care and site closure plan, for at least 50 yea rs following the cessation of injection. At the Director‘s discretion, the monitoring will continue until the geologic sequestration project no longer poses an API, along with the MSDG, believe s there are three problem s with the closure standard in proposed section 146.93(b). First, the presumption that monitoring should continue for 50 years is unnecessary and counterproductive. A straight performance standard is preferable to this or any other fixed time period becau se it provides a clearer

standard and an incentive to maximize the understanding of site and project performance and as such is more protective of USDWs. Second, the proposal requires a showing that the CO2 plume has ―stabilized‖, which is

undefined. Ces sation of plume movement is not necessarily essential to show that aDecember 2 3 , 2008

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Provision EPA Proposal API Comments Rationale

no longer poses an endangerment to
USDWs. endangerment to USDWs

. until closure is

authorized pursuant to § 146.93(b)(3). project poses no threat of endangerment to
USDWs

— plumes that are still moving may, nonetheless, remain contained. Instead, it is more protective to show that the plume is not expected to encounter a leakage pathway. Third, the required showing that ―no additional monitoring is needed‖ does not provide guidance regarding how an operator is to show that no additional monitoring is needed. The proposal below provides specific guidance on w hat the operator must show.

API, in concert with the MSDG, recommend s the standard in the proposed alternative language for section 146.93(b) below because it sets forth detailed criteria, all of which must be satisfied, to demonstrate that the site does not pose an endangerment to US DWs. The specific criteria listed in our proposal will serve to provide the Director with the requisite information to make the appropriate determination. The advantage of this approach is that it establishes clear criteria that an operator must demonstr ate before obtaining site closure based upon particular site characteristics and is, therefore, reasonably applicable to any storage site as opposed to a standard based upon a fixed

duration. Furthermore, it is more stringent than a purely discretionary a pproach because it establishes specific criteria that must be shown before site closure may be granted. We believe this language, which is an extension of work done by the World
Resources Institute and the Ground Water Protection Council, avoids the noted shortcomings and provides stronger protection for USDWs.December 2 3 , 2008

44 Rule

Provision EPA Proposal API Comments Rationale

146.93(b) (2) If the owner or operator can

demonstrate to the satisfaction of the Director before 50 years, based on monitoring and other site

- specific data, that the geologic seq uestration project no longer poses an endangerment to USDWs, the Director may approve an amendment to the post

- injection site care and site closure plan to reduce the frequency of monitoring or may authorize

site closure before the end of the 50

- year perio d. (2) If T he owner or operator can request and

demonstrate to the satisfaction of the Director before 50 years, based on monitoring and other

site

- specific data, that the geologic sequestration project no longer poses an endangerment to USDWs, the Directo r may approve an amendment to that the post

- injection site care and site closure plan should be revised to reduce the frequency of monitoring or may authorize site
closure before the end of the 50

- year period. (See above)

(3) Prior to authorization for 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 t he geologic sequestration project does not pose an endangerment to USDWs. (3) Prior to authorization for site closure, the owner or operator must submit to the Director

a demonstration , demonstrate to the Director, based on monitoring

, and other site

- spe cific data

, and modeling that is reasonably consistent with site performance 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 and is

not expected to pose an endangerment to
USDWs. The Director shall approve closure if

the owner or operator demonstrate s , based on the current understanding of the site, including monitoring data and/or modeling, all of the following: (i) the estimated magnitu de and extent of the project footprint (CO2 plume and the area of elevated pressure), (ii) the estimated location of the detectable CO2 plume; (iii) that there is no significant leakage of either CO2 or displaced formation fluids that is endangering USDWs; (iv) that the injected or displaced fluids are not expected to migrate in the future in a manner that encounters a potential leakage pathway into a USDW; (v) that the injection wells at the site completed into or through the injection zone or confining zo ne are plugged and abandoned in accordance with these requirements; and (vi) any remaining project monitoring wells at the site are being managed by a person and in a manner acceptable to the Director. API edits establish the performance based

criteria for selecting the monitoring period.

EPA should recognize that under any given set of site specific conditions some of these criteria may not be fully satisfied. EPA should retain the ability to waive individual monitoring

criteria described here to reflect that situation.December 2 3 , 2008

45 Rule

Provision EPA Proposal API Comments Rationale

(4) If such a demonstration cannot be made (i.e., if the carbon dioxide plume and pressure front have not stabilized) after the 50

- year period, the owner or operator must submit to the Director a plan to continue post

- injection

site car e. (4) If such a demonstration cannot be made (i.e., if the carbon dioxide plume and pressure front have not stabilized) after the 50

- year period, the owner or operator must submit to the Director a plan to continue post

- injection site care. No longer nece ssary given changes above.

146.93(c) (c) Notice of intent for site

closure. The owner or operator must notify the Director at least 120 days before site closure. At this time, if any changes have been made to the original post

- injection site care and s ite closure plan, the owner or operator must also provide the revised plan. At the discretion of the Director, a shorter notice period may be allowed.

146.93(d) (d) After the Director has

authorized site closure, the owner or operator must plug all mo nitoring wells in

a manner which will not allow movement of injection or formation fluids that endangers a USDW.

(e) Once the Director has authorized site closure, the owner or operator must submit a site closure report within 90 days that must therea fter be retained at a location designated by the Director. The report must include:

(1) Documentation of appropriate injection and monitoring well plugging as specified in § 146.92 and paragraph (c) of this section. The owner or operator must provide a copy of a survey plat

which has been submitted to the local zoning authority designated by the Director. The plat must indicate the location of the injection well relative to permanently surveyed benchmarks. The owner or operator must also submit a

copy of the plat to the Regional Administrator of the appropriate EPA (e) Once the Director has authorize s d site closure, the owner or operator must submit a site closure report within 90 days that must thereafter

be retained at a location desi gnated by the

Director

. after completion of all closure operations . The report must include:

(1) Documentation of appropriate injection and monitoring well plugging as specified in §146.92 and paragraph (c) of this section. The owner or operator must prov ide 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 (s) relative to permanently surveyed benchmarks. The owner or operator must also submit a copy of the plat to the Regional Administrator of the appropriate EPA Regional Office; Once the site closure report is submitted to the Director, the operator cease to bear responsibility for any further record retention. At this point, EPA becomes t he steward of information for the project.December 2 3 , 2008

46 Rule

Provision EPA Proposal API Comments Rationale

Regional Office;

(2) Documentation of appropriate

notification and information to such State, local and tribal authorities as have authority over drilling activities to enable
such State and local authorities to impose appropri ate conditions on subsequent drilling activities that may penetrate the injection and confining zone(s); and

(3) Records reflecting the nature, composition and volume of the carbon

dioxide stream.

146.93 (f) Each owner or operator of a

Class VI inject ion well must record a notation on the deed to the facility property or any other document that is normally examined during title search that will in perpetuity provide any potential purchaser of the property the following information:

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

(2) The name of the State agency, local authority, and/or tribe with which the survey plat was filed, as well as the address of the Regional Environmental Protection Agency Office to which it was submitted; a nd

(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 theDecember 2 3 , 2008

47 Rule

Provision EPA Proposal API Comments Rationale

post

- injection site care period. The owner or operator must deliver the

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

must thereafter be retained at a location designated by the Director for that

purpose.

146.94 14. Em ergency and remedial response.

(a) As part of the permit application, the owner or operator must provide the Director with an emergency and remedial response plan that

describes actions to be taken to address movement of the injection or formation

fluids that may cause an endangerment to a USDW during construction, operation, closure and post

- closure periods.

146.94(b) (b) If the owner or operator

obtains evidence that the injected carbon dioxide stream and associated pressure front may cause an endang erment to a USDW, the owner or operator must:

(1) Immediately cease injection;

(2) Take all steps reasonably necessary to identify and characterize any release;

(3) Notify the Director within 24 hours; and

(4) Implement the emergency and remedial respo nse plan approved by

the Director. (b) If the owner or operator obtains evidence that the injected carbon dioxide stream, displaced

formation fluids or and associated pressure front may cause an endangerment to endangers a USDW, the owner or operator must:

(1) Immediately cease injection in a prudent manner considering circumstances

. (2) Take all steps reasonably necessary to identify and characterize the endangerment posed ;

(3) Notify the Director or the designated representative within 24 hours of becom ing aware of the endangerment ; and Technical clarifications.

There is a slight change that immediately ceasing injection could have adverse impacts on other aspects of the operation.

(c) The Director may allow the operator to resume injection prior t o remediation if the owner or operator demonstrates that the injection operation will not endanger USDWs.

(d) The owner or operator must notify the Director and obtain his approval prior to conducting any well (d) The owner or operator must notify the

Director prior to conducting any well workover in In critical situations, time spent obtaining approval could adversely affect the ability toDecember 2 3 , 2008

48 Rule

Provision EPA Proposal API Comments Rationale

workover. response to any case of endangerment. conduct operations or increase the level of endangerment.1

335843 .5 Rule Provisions EPA Preamble Question API Response

73 FR 43497 1. EPA seeks comment on any aspects of

the ongoing State efforts to regulate the GS of CO2 and how these efforts might be used to better inform a final Federal rulemaking. EPA

Notice 43497. API support s the implementation of partial primacy for Class VI separately from other classes of wells

.

73 FR 43502 2. Injection of CO2 for the purposes of

enhanced oil and gas recovery (EOR/EGR), as long as any production is occurring, will

continue to be permitted under the Class II program. EPA seeks comment on the merits of this approach since owners or operators of some Class II EOR/EGR wells may wish to use wells for the purposes of production and GS prior to the field being completely depleted.

E PA Notice 43502. API strongly supports the absence of an economic test for oil and gas reservoir “depletion.” API
contends that EOR needs to be maintained under the current Class II program and supports EPA’s proposal that any storage that occurs under EO R continues to be handled under the Class II program. Additionally, API support s the creation of a subclass under Class II (e.g “Class IIB”) for storage operations in hydrocarbon formations after EOR activities. See API’s proposed section 146.25.

146. 81(c) 3. EPA seeks comment on the approach

to grandfather construction requirements at the Director’s discretion for existing Class I, Class II, and Class V wells seeking to convert to Class VI wells, and whether additional construction requirements would be necessary to prevent endangerment to USDWs from the GS of CO2.

EPA Notice 43502. API supports this provision . Candidate Class I and

Class V wells for grandfathering will have a demonstrated record of performance under their existing operations and MIT programs to demonstrate sound performance and adequacy of well integrity that can be used as a basis for conversion to the Class VI program.

For Class II wells, API propose s that they remain under the Class II program when transitioning from

EOR to GS.

146.81(c) 4. Additionally, EPA seeks comment on

how the grandfathering approach for existing wells may affect compliance with the other requirements in its proposal. EPA Notice

43502. All components of the existing wells with a proven record of performanc e should be grandfathered unless there are specific USDW endangerment concerns identified by the Director. See Comment

above.

144.6(f)

146.5

146.81 5. EPA is proposing to preclude the

injection of CO2 for long

- term storage into coal seams where they are above the lowermost USDW. EPA requests comment on this proposed prohibition. EPA Notice 43503. API opposes this restriction

. Qualification of a

formation for storage should be based on performance

- based standards and site

- specific

considerations.

144.6( f)

146.5

146.81 6. The location and proximity of other

formations to USDWs may preclude their use for GS. EPA seeks comment on prohibiting injection into such formations if they are above
the lowermost USDW. EPA Notice 43503. R estrict ing injection to form ations below the lowermost underground source of drinking water or
USDW is not necessary for the protection of USDWs

and would remove a vast number of viable formations from consideration. Industry has shown that it can operate CO 2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW below the injection zone. Moreover, under the proposed rule, there are other measures that

w ould provide real assurance of formation integrity and require operators to demonstrate that their project will not endanger USDWs, making the lowermost USDW restriction unnecessary.2 Rule Provisions EPA Preamble Question API Response

146.81(b)

146.81(d) 7. By defining “carbon dioxide stream” to

exclude h azardous wastes (146.81(d)), EPA’s rule, if finalized, assures that it would apply only
to CO2 streams that are not hazardous wastes as defined in 40 CFR Part 261. As a result, EPA’s proposed rule would preclude the injection of hazardous wastes in Class V I injection wells. EPA seeks comment on this approach and other considerations associated with the presence of “impurities” in the CO2

stream. EPA Notice 43503. API agrees with the concept that Class VI wells should not be injecting hazardous wastes but i s proposing some modifications to EPA’s definition of

CO2 stream in the rule. The modifications reflect the
fact that the source of CO2 should not be a factor in the context of defining the CO2 stream. The rule applies to the injection of CO2 and should not address the origins of the materials since that is beyond the scope of this regulation. The o riginal text would have precluded injection of CO2 from some

sources. The question of how CO2 should be

accounted for , and from what sources, in a GHG

manage ment and accounting system is beyond the scope of this regulation.

73 FR 43504 8. Class VI requirements and permits will

need to be carefully structured to ensure that they do not “authorize” inappropriate hazardous releases. This would include clarifyin g if there are potential releases from the well which are outside the scope of the Class VI permit. EPA requests comment on particular situations where this might occur. EPA notice 43504. Well chosen sites should prevent these conditions from occurring. A t the same time, permit writers should not write permits so restrictive as to make the undertaking of a GS project untenable. EPA should remember that CERCLA liability will not only impact owners and operators of GS projects, but also hundreds, thousands, and even more numerous pore

space owners

. EPA should consider the threat of subjecting these pore space owners to CERCLA liability. Their property interests in the C O 2 GS project injection zones could subject them to strict, joint, and several liability under CERCLA pursuant to whatever liability theories might be developed by future litigants seeking compensation for response and remediation costs incurred in the cleanup of releases from geologic sequestration injection zones. EPA should recognize the significant chilling effect CERCLA liability concerns will have on GS projects, and seize the opportunity in this rulemaking to alleviate any CERCLA liability concerns to the greatest extent possible.

73 FR 43504 9. EPA also requests comment on other

con siderations associated with the presence of impurities in the CO2 stream related to

CERCLA. EPA Notice 43504. API is concerned that potential CERCLA liabilities will have the potential to chill enthusiasm for undertaking GS projects

. EPA needs to respond clearly and positively to this concern by developing appropriate language in the regulations and permits to provide the clarity and assurance needed to promote continued research and development for GS projects.

73 FR 43506 10. EPA’s proposal would prov ide the

Director the discretion to require the owner or operator to identify and characterize additional confining and containment zones above the primary (i.e., lowermost) confining zone that could further impede vertical fluid movement and allow for pres sure dissipation. EPA says that these layers could provide additional sites API holds that secondary containment is not mandatory

. There are many areas where a single confining zone can be sh own to be highly protective of USDWs. Adequacy of containment must be done

on a site

- specific basis. This requirement would reduce the number of CCS storage site opportunities while increasing costs and not enhancing protection.3 Rule Provisions EPA Preamble Question API Response

for monitoring, mitigation, and remediation. EPA’s proposal would not require that these
additional zones be identified for all GS sites because their absence does not necessarily indicate inappropriateness of a GS site. However, if such zones are present, information about their characteristics can provide inputs for predictive models, identify appropriate monitoring locations, and improve public confidence in and acceptance of a p roposed GS site. EPA specifically seeks comment on the merits of requiring the identification of these

additional zones. EPA Notice 43506.

146.82(c)

146.84

146.9 0(d)(2) 11. EPA believes that predicting the

complex multi

- phase buoyant flow of the CO2,

“co

- injectates,” and compounds that may be mobilized due to injection requires the sophistication of computational models. EPA proposes that the owners or operators o f GS wells be required to delineate the AoR for CO2 GS sites using computational fluid flow models designed for the specific site conditions and injection regime. EPA seeks comment on the use of modeling for AoR delineation. EPA

Notice 43506. Modeling is well developed technology that can readily simulate complex behavior of injected CO2. It

should be one of the techniques used to delineate

the AoR. Modeling alone though should not be the

s ole basis for determining the Ao R. Other technologies such as se ismic, use of off

- set wells, should also be considered when delineating the proposed AoR.

The oil and gas industry has a great deal of experience that can be generally applied in the
delineation of the AoR.

The most complex model is not always necessary to adequately delineate the AoR. Some CO2 EOR projects have successfully operated for decades using only production data and pressure mapping,

which has in effect defined AoR.

146.84 12. In some cases, owners or operators

may choose to use proprietary mode ls (i.e., not available for free to the general public). EPA says it is aware that the use of proprietary codes may prevent full evaluation of model results (e.g., NRC, 2007). Several popular codes in the petroleum

- reservoir engineering discipline are prop rietary and owners or operators of particular sites may prefer to use these codes as they have previous experience with them, and they have been used in peer

reviewed studies to model CO2 sequestration. When using a proprietary model, owners or operators s hould clearly disclose the code assumptions, relevant equations, and scientific basis. EPA seeks comment on allowing the use of proprietary models for GS sites. EPA Notice

43507. Use of p roprietary models should be allowed. EPA ’s
C onfidential B usiness I n formation requirements should apply to any proprietary model used

.

146.84 13. EPA seeks comment on the

applicability of computational fluid flow models for delineating the AoR of GS sites. EPA Notice

43507. While computational fluid flow models can infor m the delineation of the AoR, modeling shouldn’t be the sole criteria for determining AoR. (See Comment # above also.)4 Rule Provisions EPA Preamble Question API Response

146.84 14. EPA seeks comment on requiring the

reevaluation of the site AoR on a periodic basis,

under what conditions the AoR should be reevaluated, and the appropriateness of a 10

- year minimum fixed frequency for AoR

reevaluation. EPA Notice 43507. Rather than a fixed time period, API recommends following a performance based approach that would be based on significant changes in injecti on parameters or anomalous monitoring results.

146.84(f) 15. EPA proposes to allow a phased

approach to corrective action but says this may not be appropriate in all situations; therefore EPA is proposing that the Director have the

discretion to decide t o allow this approach, based on the understanding of relevant geologic and site conditions. EPA invites public comment on the merits and frequency of reevaluation of the AoR as well as the phased corrective action approach for GS wells. EPA

Notice 43508. API supports the EPA proposal. The phased approach allows the sound economic execution of the project over time without endangering USDWs. This approach prevents an operator from the unnecessary expense of remediating wells in an area that ultimately may not be affected by the storage project. Frequency of reevaluation should be based on site performance as noted in the prior comment.

146.86(b) 16. EPA seeks comment on the proposed

GS well requirements for depth of surface casing, the cementing of long

- string casing, and construction with a packer set opposite a

cemented interval. EPA Notice 43509. Generally the surface casing is set below the lower USDW but it should be recognized that this is not appropriate in all geologic settings. In some areas

U SDWs can extend much greater depths than would be appropriate for setting of surface casing. Regulations should recognize these situations and allow a surface casing setting depth that may not fully
cover the USDWs.

API opposes the requirement for cemen ting the long string casing back to surface. Cementing requirements should focus on ensuring competent

isolation and seal across the injection zone and confining zone(s). Sealing the annulus between the long string and surface casing could limit an

opera tors ability to monitor for leakage or conduct remedial operations.

Regarding packer setting depth, the director should retain discretion for allowing variation from this requirement.

146.81(c) 17. EPA also seeks comment on how the

proposed grandfatherin g provisions for existing wells (construction requirements) may affect compliance with the above, proposed construction requirements. EPA Notice 43509. Grandfathering should be handled on a case

- by

- case basis. The standard for grandfathering should be

dem onstrated performance of the well at protecting
USDWs. Because the act of injection would be the same for CO2 EOR and CO2 storage, Class II CO2

EOR wells should be deem ed to meet the requirements of 146.86 and 146.87 upon notification.

The purpose of gran dfathering is to recognize that some wells may not meet construction requirements
of Class VI wells

, but the performance of Class II CO2 injection wells justifies their use as Class II CO2 Storage wells (“Class IIb”) or Class VI wells if EPA does not adopt a special subclass for storage under5 Rule Provisions EPA Preamble Question API Response

the Class II program

.

146.86 18. EPA seeks comment on the merits of

horizontal well drilling techniques for GS wells and the applicability of well construction requirements discussed in this proposal. EPA

Notice 4350 9. Drilling of directional and horizontal wells is a n

e stablished technology that can significantly reduce surface impacts of a GS project and improve the injection rate of a well. The CO2 injection wells at In
Sal a h , Sl e i pner, and many in Texas are horiz ontal or

have horizontal sections.

146.86

73 FR 43510 19. EPA seeks comment regarding

requirements for degradation

- resistant well construction materials, such as acid

- resistant cements and corrosion resistant casing. EPA

Notice 43510. The well should be looked at as a system such that not each individual component needs to be CO2 resistant as long as the entire system provides an

effective barrier under the subsurface conditions

. Industry experience with CO2 EOR strongly supports

the use of conventional oil field tubing, casing, and cements. Industry experience over the past 35 years has led to the development of corrosion mitigation measures (e.g. plastic or epoxy lined tubing, use of corrosion inhibitors, and proper dehydration of CO2) that provide a high degree of protection and mitigate any corrosive effects of injected CO2.

146.88(a) 20. EPA is requesting comment on the

extent and scope to which hydraulic fracturing should be allowed during GS injection, and whether the use of fracturing for the pu rposes of well stimulation is appropriate. EPA Notice

43511. The use of fracturing for stimulation should be allowed provided that there is no damage to the confining unit that would result in endangerment of
USDWs. There are computer simulators to predic t fracture behavior so the impact on the confining zone can be anticipated.

73 FR 43511 21. EPA is also requesting information to

better qualify the use of fracturing for GS injection in specific geologic settings and rock formation lithologies. EPA Noti ce 43511. See response to #20.

146.88(e) 22. EPA seeks comment on the merits of

requiring down

- hole shut

- off valves in GS wells.

EPA Notice 43511. Over

- pressure protection is best achieved by ensuring compatibility of the casing/tubing material design st rength with the surface injection (compression) system. Down

- hole shut

- in devices are not appropriate for this application. These devises are installed in the tubing string and are typically near the surface of the well. They’re

intended to seal the tubi ng in the event of catastrophic failure of the wellhead. These devises would provide little if any protection to USDWs. Is not practicable to install these devises deep within the well (e.g. shortly above the packer). Additionally

these devises create a restriction on running other tools like logging tools in the well and therefore could limit an operators ability to do required monitoring and diagnostic work. Lastly, these devises require periodic testing and maintenance which could require either pull ing the devise by wireline or by pulling the entire tubing string depending on the type of devise6 Rule Provisions EPA Preamble Question API Response

installed. Either of these activities would be disruptive and costly to the overall project operations.

A more appropriate approach would be installation of landing nipples at appropriate points in the tubing string which would allow use of wireline retrievable plugs when needed.

144.6(f)

146.5

146.81 23. EPA is aware that the proposed

requirement of injecting CO2 below the lowermost USDW may preclude inject ion into certain targeted geologic formations, which may be storage sites currently under consideration for GS. As a result, the Agency is considering and requesting comment on alternative approaches that would allow injection between
and/or above the lowe rmost USDW, and thus potentially allow for more areas to be available for GS while preventing USDW endangerment.

EPA Notice 43512. Injection above the lowest USDW should be allowed but the operator must demonstrate confinement above and below the injectio n formation

. Retaining

the restriction would remove a significant number of viable formations from consideration. Industry has shown that it can operate CO 2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW below the injection zone. Moreover, under the proposed rule, there are other measures that would provide real assurance of formation integrity and require operators to demonstrate that their project will not endanger USDWs, making the lowermost USDW restriction

unnecessary.

144.6(f)

146.5

146.81 24. EPA is soliciting comment on whether

CO2 injection should be allowed into an injection zone above the lowermost USDW,

wh en the Director determines that geologic conditions (e.g., thousands of feet of intervening formations between the injection zone and the overlying and/or underlying USDWs) exist that will prevent fluid movement into adjacent
USDWs. EPA Notice 43512. See response to #23 . CO2 injection zones should be selected based upon site specific evaluation of performance based criteria.

73 FR 43512 25. EPA is also requesting comments on

whether aquifer exemptions should be allowed for the purpose of Class VI inject ion, and under what conditions should such aquifer exemptions be approved. EPA Notice 43512. There should be no changes to the aquifer exemption requirements in the UIC program as they exist today. Each aquifer exemption should be considered on a

case

- spe cific basis.

73 FR 43512 26. EPA seeks comment on whether the

Agency should set a minimum injection depth requirement for CO2 GS, rather than require that such injection take place below the
lowermost USDW. EPA Notice 43512. There should be no minimum de pth for injection of
CO2

. The primary consideration should be protection of USDWs. A requirement for a minimum depth suggests an intention by EPA to require injection of CO2 in a supercritical phase. Such a requirement is not appropriate since there may be areas where injection of CO2 in other phases may be the only option. Again, site

- specific evaluation and protection of USDWs should be the basis for determining depth of injection.7 Rule Provisions EPA Preamble Question API Response

73 FR 43513

- 15 27. EPA’s proposal allows Directors’

discretion on whe ther to require the use of tracers, and if so, what types of tracers. EPA
seeks comment on the use of tracers in CO2 GS operations, and any potential impact of tracers on human health or ecosystems as they
relate to USDWs. EPA Notice 43513. EPA should not mandate the use of tracers. The value of tracers has been questioned by many.

F urther research of their use needs to be conducted before any final language is approved. Modeling and monitoring are much more reliable te chniques for tracking the plume of injected CO2.

146.89(b) 28. EPA’s proposal would require owners

or operators of Class VI GS projects to monitor internal mechanical integrity of their injection wells by continuously monitoring injection pressure, flow rate, and injected volumes, as

well as the annular pressure and fluid volume to assure that no anomalies occur that may indicate an internal leak. EPA requests comment on the practicability of this requirement. EPA Notice 43513. There is concern regarding what constitutes

continuous monito ring. Industry agrees that regular monitoring of the parameters identified by EPA is appropriate. Our experience with CO2 EOR strongly shows that daily monitoring of most of these parameters is adequate (exceptions to this would be

on a site

- specific basi s). Recording should generally be done on a daily basis and reporting on a semi

annually basis. As a guiding principle, the frequency of monitoring should be determined by the level of risk posed by the injection operation.

146,89(c)

146,90(e) 29. EPA se eks comment on the appropriate

frequency of internal and external MITs for GS injection wells, the appropriate types of MITs, and how to optimize MIT methods for GS. EPA

Notice 43514. Timing for conducting MITs, should be based on risk and performance fac tors. Industry experience with CO2 EOR Class II program requires MITs every 5 years. This frequency has proven protective of
USDWs. Given the similarities between CO2 EOR wells and GS wells, API recommends 5

- year frequency in this case as well. The MI T should test integrity of the long string casing, packer, and tubing and to the extent practicable, should test the integrity of the cement isolating the injection zone. There are many methods for conducting MITs. EPA should allow operators adequate fle xibility in selecting the appropriate methods for their specific situation. API RP90 provides good examples of various methods for detecting mechanical failures, managing those risks, and conducting MITs.

146.90 30. EPA seeks comment on the

requirement for monitoring of GS sites for the purpose of tracking the location of the CO2 plume and associated pressure front over time.

EPA Notice 43514 The frequency of monitoring should be dictated by

site

- specific operational and geologic conditions

combined wi th the results of monitoring with model predictions. The guiding principle for monitoring is to verify proper confinement of the CO2 and ensure protection of USDWs. EPA should recognize that use of modeling and other monitoring techniques are

relativel y qualitative processes that can have varying degrees of accuracy that will improve over time in an iterative process.

146.90(f) 31. EPA’s proposal would require that

owners or operators perform a pressure fall

- off test at least once every five years. EPA seeks comment on the use and frequency of pressure

fall

- off testing for GS wells. EPA Notice 43515. We recommend that an initial falloff test be conducted upon completion of the well prior to any operational injection and after the first year of operatio nal injection. Following the first year, the frequency should be at the discretion of the Director but the frequency should be aligned with the8 Rule Provisions EPA Preamble Question API Response

reevaluation of the A o R.

146.90(g) 32. Based on information evaluated to date,

EPA believes that tracking th e plume and pressure front is an important companion step to address any uncertainties associated with initial AoR modeling and requests comment on this approach and more efficient alternatives that may be used to track the plume and pressure front. EPA N otice 43516. Based on experience to date, CO2 plume can be monitored using surface or wellbore seismic and possibly some remote satellite techniques. Monitoring of the pressure front will be more difficult since that requires data fr om the injection forma tion

that can only be obtained by drilling a well (which introduces additional artificial penetrations into the containment system)

. Modeling can estimate the movement of a pressure front. Those estimations are limited by the accuracy of the model and its iterative adjustments as previously mentioned.

EPA should note that plume and pressure front are different concepts and should not be confused. They yield information on two different metrics. One tells you about the remaining capacity of the storage

formation and the other describes the direction and movement of the CO2 plume.

73 FR 43517 33. EPA seeks comment on the appropriate

amount and types of monitoring that should be conducted at a GS site. Specifically, EPA seeks comment regarding the usefu lness of indirect geophysical monitoring and surface air and soil gas monitoring. In addition, EPA seeks comment regarding the use of a Director

approved monitoring plan for GS sites. EPA

Notice 43517. Monitoring techniques and frequency should be

determi ned on a site

- specific basis. Selection of monitoring types and frequency should balance the potential risks posed by the project with the cost of monitoring.

Surface and soil gas monitoring do es not add value to the protection of USDWs. Many of the surf ace and soil gas monitoring techniques currently being evaluated lack the track record necessary for use in a regulatory compliance setting. Moreover, the potential for false

- positives could undermine public confidence in GS technologies. EPA should defe r on using surface and soil gas monitoring technologies until the DOE Regional Partnerships can

demonstrate their effectiveness.9 Rule Provisions EPA Preamble Question API Response

146.90

146.93(a)

146.94(a) 34. EPA is proposing that permit

applications for GS sites include several plans not currently re quired under existing UIC regulations. These plans include a monitoring and testing plan, an AoR and corrective action plan, and a post

- injection site care and site closure plan. EPA seeks comment on the merits of requiring plans for monitoring, AoR, and p ost

injection site care as part of a permit application. EPA Notice 43517. The development of such plans is a good idea because it negates prescriptive regulation of the

process. API is concerned that every modification of a plan may trigger a major pe rmit modification. Although actual monitoring of injection formation is

most effective , there is still the unintended consequence of penetrating the confining zone to gain that data. The number of monitoring wells

should not be established in advance. I t is unclear how monitoring well construction, operation, and closure will be regulated since these are not actual injection wells.

Timing of development of plans should be linked to the actual activity being addressed (i.e. staged) . It

should not be nec es sary to prepare and submit a site closure plan or the post

- closure monitoring plan at the start of the project, particularly considering that

the se a c tivit ies will not occur for many years after the project starts.

146.91 35. EPA seeks comment on the fr equency

of all proposed reporting requirements. EPA

Notice 43517 Frequency should reflect the level of risk associated with the activity. Semi

- annual reporting is adequate. Reporting should be on a project basis as opposed to

a well basis consistent wit h 146.23(c).

146.91(c) 36. EPA seeks comment on the

requirement for electronic reporting in its proposed rule. EPA Notice 43518. API strongly supports the concept of electronic reporting. Industry’s objections to prior proposals for electronic reportin g have been with the scope and breadth of information (incremental over written reports) that the Agency has previously proposed. Electronic reporting equivalent to existing written reports would be supported by API. Until these

concerns related to elect ronic reporting are resolved, such reporting may be encouraged but should not be required.

73 FR 43518 37. In addition to the above recordkeeping

and reporting requirements, EPA considered a requirement for owners or operators of GS sites to provide an an nual report during the lifetime of the project, including the post

- injection period, regarding the GS operation. Although EPA has not included a requirement for this report in its proposal, EPA seeks comment regarding the necessity for such an annual repor t. EPA

Notice 43518. An Annual report is not necessary given the other reporting requirements in the Rule. Alternatively, if this report was to replace the other reporting requirements, there would be value to the proposal.10 Rule Provisions EPA Preamble Question API Response

73 FR 43519

- 20

146.93(b) 38. EPA is proposing using a combination

of fixed timeframe and a performance standard as described above. EPA is tentatively proposing a post

- injection site care (monitoring) period of 50 years with Director’s discretion to change that period to lengthen or s horten the 50 year period if appropriate. EPA requests comment on the proposed use of a tentative 50 year fixed timeframe that could be modified at the Director’s discretion based on monitoring and modeling data. EPA Notice 43519. API strongly objects to the use of a 50

- y ear default monitoring period. EPA offers no rationale for this arbitrarily

- selected period of 50 years. Establishing a fixed and unusually long time period may create a significant barrier for operators considering entry into CCS opera tions. Criteria for determining the period for post

- injection site care should be performance

based and a function of the site specific characteristics of a project such as project size, geologic factors, and relative risk of the project. (API

offers such criteria in our edits to §146.93(b)(3).)

Clear guidelines also need to be established regarding when operators have met the performance standards that determine site closure. Specifically, the standard that the project no longer poses an endangerment to USDWs needs to be defined using

reasonable risk

- based criteria.

146.93 39. EPA is requesting comments on the

proposed requirements for well plugging, post

injection site care, and site closure, including the proposed requirements for the post

- injection

t ime period. EPA Notice 43520. See question 38 above regarding post closure time periods.

146.93(b)(2) 40. In addition, EPA seeks comment on

whether the Director should be allowed to shorten the timeframe based on performance information, and whether EPA s hould require a shorter or longer post injection period if data suggests the time frame should be adjusted.

EPA Notice 43520. See question 38 above regarding post closure time periods.

144.36 41. Current UIC guidance describes trust

funds as a form of fi nancial assurance. The owner or operator may deposit funds into the trust fund in phases; that is, either over the term of the initial permit or over the remaining operating life of the injection well, as estimated in the well plugging plan, whichever peri od is shorter. Because of the possibility that the owner or operator may face financial distress prior to the trust being fully funded, EPA is considering a guidance approach that would recommend adopting a pay in period of three years for GS projects, con sistent with other similar programs in the Agency. EPA Notice

43521. Industry should have a variety of options for meeting financial assurance based upon the companies’

discretion. Options should include self

- insurance, insurance, surety bonds or other a ppropriate financial

instruments.11 Rule Provisions EPA Preamble Question API Response

73 FR 43521 42. Current UIC regulations for Class I

hazardous waste injection allow for the use of insurance for purposes of demonstrating financial responsibility. However, insurance was not included as part of the guid ance provided for Class II injection because this insurance mechanism was and still is, rarely used for the purpose of demonstrating financial assurance for injection wells. EPA is assessing whether to provide guidance on the use of insurance providers and , if so, whether to update eligibility requirements for insurers for GS wells consistent with other current Federal agency practices. EPA Notice 43521. See response to 41

73 FR 43522 43. EPA is assessing whether a financial

ratings threshold for all comp anies using a self

guarantee, similar to those used by other Federal agencies, is appropriate. The Agency also is considering what constitutes an appropriate financial rating threshold, and whether a financial rating greater than BBB or Baa (i.e., the curr ent rating threshold established under the UIC regulations) is appropriate for GS wells. EPA Notice 43522. See response to 41

146.85 44. EPA is requesting comments on

whether financial responsibility mechanisms to be recommended in EPA guidance should be adjusted in the manner described, whether additional instruments should be included, and whether other adjustments to the financial responsibility mechanisms should be considered, all subject to EPA’s authority under
the SDWA. EPA Notice 43522. See resp onse to 41

73 FR 43522 45. The Agency is also requesting

comment on allowing separate financial demonstrations to be submitted for the plugging of the injection well and for the post

- injection site care requirements. EPA Notice 43522. See response to 41

73 FR 43523 46. EPA requests comment on adopting the

existing requirements for public participation at
40 CFR Part 25 and 40 CFR Part 124 and whether additional requirements should be included to reflect the availability of new tools for disseminating and gathering information. Such tools include cable networks, the Internet, and other new technology. EPA Notice 43523. The current provisions in Parts 25 and 124 are sufficient to inform the public. Additional requirements should not be included.

Public pa rticipation should be consistent across programs. If EPA believes the public participation requirements should be expanded, it should be done in a holistic manner across programs.12 Rule Provisions EPA Preamble Question API Response

73 FR 43522

- 23 47. EPA also requests comment on ways to

enhance the publi c participation process, including engaging communities in the site characterization process as soon as candidate
locations are identified. EPA Notice 43523. API does not believe that the public participation process should be extended to the site

charact erization stage of a GS project

, p articularly given that many sites might be characterized in the process of winnowing down t he portfolio of potential

sites

.

73 FR 43523 48. To gain authority for Class VI wells,

States, Territories, and Tribes will be r equired to show that their regulations are at least as stringent as, and may be more stringent than, the proposed minimum Federal requirements (e.g., inspection, operation, monitoring, and recordkeeping requirements that well owners or operators must meet) . Such Primacy States, Territories, and Tribes are authorized under
Section 1422 of the SDWA. EPA Notice 43523. States should be able to gain primacy as long as they show that their regulations are at least as stringent as the proposed minimum Federal req uirements . EPA should ensure that adequate funding is provided for the delegated program.

73 FR 43523

73 FR 43529 49. There may be benefits to parsing out

primacy for Class VI wells, however EPA has not made a decision on this. Allowing States,

Territori es, and Tribes to acquire primacy for only Class VI wells may encourage them to assume the responsibility of implementation and provide for a more comprehensive approach to managing CCS projects (e.g., capture, transportation, and geologic sequestration). EPA is seeking comment on the merits and possible disadvantages of allowing primacy approval for Class VI wells independent of other well classes. EPA Notice

43523. API supports the implementation of partial primacy for Class VI separately from other clas ses of wells. The geologic variation across the country justifies partial primacy.

144.36(a) 50. EPA proposes that Class VI injection

well permits would be issued for the operating life of the GS project including the post

- injection site care period. EPA seeks comment on the merits of this approach. EPA Notice 43523. A permit for the life of the project would ensure the continuity of operations. Shorter time periods would yield administrative burden without commensurate

benefits.

73 FR 43527 51. The Ag ency assumes three monitoring

wells per injection well for the purpose of estimating national costs; however, the Agency recognizes that operators and primacy agency Directors may choose more or fewer monitoring wells depending on project site characterist ics. Because the monitoring wells and associated costs represent a significant component of the Cost Analysis, the Agency acknowledges that this factor may be significant in the overall uncertainty of the Cost Analysis. EPA requests

comment on whether thre e monitoring wells per injection well is an appropriate costing assumption. EPA Notice 43527. It is difficult to select a realistic ratio since each site

will have its own characteristics that would significantly affect the number of monitoring wells

nece ssary.

The attached report prepared by ARI for API discusses the cost modeling in greater detail.13 Rule Provisions EPA Preamble Question API Response

73 FR 43531 52. The public is invited to submit

comments or identify peer

- reviewed studies and data that assess the effects of early life exposure to changes in drinking water quality that may be caused by geologic sequestration

of carbon dioxide. EPA Notice 43531. API is not aware of anything unique about CO2 injection or its potential impacts on drinking water quality that would not be addressed within the existing drinking water program. The data EPA has on developing drinking water standards and MCLs

can be used in this situation.ADVANCED RESOURCES INTERNATIONAL, INC.

4501 Fairfax Dr, Suite 910, Arlington, Virginia 22203 Phone: (703) 528

- 8420 Fax: (703) 528

- 0439 

# Memorandum

T o: Steve Crookshank; American Petroleum Institute

From: Michael Godec; Advanced Resources International, Inc.

Date: 10/17/2008

Re: C omments re the EPA’s Preliminary Cost Analyses for U nderground Injection of
CO 2 for the Purpose of Geologic Sequ estration

On July 25, 2008, EPA published proposed federal requirements under the Safe Drinking Water Act (SDWA) for underground injection of carbon dioxide (CO 2 ) for the purpose of geologic sequestration (GS). 1 As part of this proposal, EPA performed some preliminary cost analyses, to potentially provide some insight on the relative costs and

benefits associated with the se proposed requirements.

This memo summarizes the results of our review of the two main documents serving to support the EPA benefit/cost analyses:

“Geologic CO 2 Sequestration Technology and Cost Analysis” (June 2008),

“ Cost Analysis for the Proposed Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Proposed GS Rule)” (July 2008).

Our major findings/comments related to this review are provided below.

In several significant areas , the assumptions for what is required to comply with the new requirements in the cost analyses seem far less comprehensive than what appears to b e described in the proposed regulations

. Preliminary interpretation of the requirements set forth in the proposed rule appear, in

some these cases , to be much more comprehensive than that assumed to be performed as part of the cost analyses. Several exa mples are provided below:

Geologic Siting Requirements

The costs assumed to be associated with the process of geologic site evaluation seems to be underestimated significantly relative to what the proposed GS rule require s

. The

rule contains over four page s worth of fairly detailed requirements for GS site selection and approval , including the following for owners or operators to prepare and submit :

1 Federal Register, Vol. 73, No. 144, pp. 4349 2

- 43541, (July 25, 2008)October 17 , 200 8

2 Maps and cross sections of the USDWs near the proposed injection well.

Demonstrat ion that the injection zone is: (1) sufficiently porous to receive the CO 2 without fracturing and (2) extensive enough to receive the anticipated total volumes of injected CO 2

. For this demonstration, o wners or operators need to submit geologic core data, outcrop data, seismic survey data, cross sections, well logs, and other data that demonstrate the lateral extent and thickness, strength, capacity, porosity, and permeability of subsurface formations. The y must demonstrate that the injection zone should be of a sufficient lateral ext ent that the CO 2 can move a sufficient distance away from the well and still remain in the same zone, without displacing fluids into USDWs. His would require that s tructural features of a potential injection zone reservoir, such as the lateral extent, dip, or the presence of “pinch

outs” (i.e., thinning or tapering out) can affect storage potential, w ould need to be

examined.

Data on the local geologic structure, including information on the presence of any faults and fractures that transect the confining z one and a demonstration that they

would not interfer e with containment. These data are to support determinations about whether these features, if present, could potentially become conduits for

movement of CO 2 or other fluids to shallower layers, including USDWs.

Results of geomechanical studies of fault stability and rock stress, ductility, and strength.

Information on the seismic history of the area and the presence and depth of seismic sources to assess the potential for injection

- induced earthquakes. In formation on in

situ fluid pressures is required to assess the potential for the pressures associated with injection to reactivate faults or to determine appropriate operating requirements.

Demonstration of the application one or more of a variety of techn iques to characterize the receiving zones and confining zones of proposed GS sites. For example, geologic core data, test wells, and well logs can help determine rock formations’ strength and extent. Seismic and electrical methods can be used to

reveal sub surface features. Gravity anomalies indicate density variations at depth, and gravity surveys can be used to locate voids, such as cavities and abandoned mines. Numerous geophysical logging tools can determine formation porosity. Large scale, regional pres sure tests can also provide insight into the fluid flow field and the presence and properties of major faults and fractures that may affect flow and transport of CO 2 and displaced brines.

Demonstration of the maximum sustainable injection pressures that wi ll not cause unpermitted fluid movement, i n order to assure that owners or operators not exceed an injection pressure that would initiate or propagate fractures in the confining zone

. This sh ould be based on geomechanical studies of fault stability and roc k stresses and strength, along with an examination and interpretation of geological maps and cross sections, seismic and well surveys, determination of local stress fields, and modeling,October 17 , 200 8

3 Information on the geochemistry of formation fluids that can affect whether a site is suitable for GS; to include what CO 2 may act as a solvent, mix with native fluids to form carbonic acid, lead to the potential liberation of heavy metals into the formation fluids or break down the rock matrix or precipitate minerals and plug pore spaces, therefore reducing permeability (IPCC, 2005). Studies of rock samples and review of geochemical data from monitoring wells would be needed to evaluate the impact of

these effects. O wners or operators are to submit geochemical data on a) t he injection zone, b) the confining zones, c) containment zones above the confining zones in which any potentially migrating CO 2 could be trapped, d) all USDWs, and e) any other geologic zone or formation that is important to the proposed monitoring

progra m.

According to the EPA cost analysis, the acquisition and interpretation of most or all of that described above, along with the reporting of this information according to the specifications set forth in the proposal, would amount to about 3.5 person

- mont hs of effort, or about $90,000. Recent Advanced Resources’ experience on the DOE SECARB GS demonstration project indicates, at least for this early project, costs are likely to be five to ten times or more than this for a small scale pilot project

. Similar work

Advanced Resources has done for the I nternational Energy Agency Greenhouse Gas Program (IEA GHG) indicates that costs for site selection and project design for a commercial scale project could range from $5 to $20 million per site. 2

In particular, m eeting many of the requirements set forth in the proposed regulations for
GS site selection will very likely require the drilling of stratigraphic and/or delineation

wells . This will be especially true in deep saline aquifers. N o costs associated with such wells appear to be considered in the EPA costs analyses for site selection (see discussion below).

Record Keeping and Reporting Requirements

EPA proposes that :
“...permit applications for GS sites include several plans not currently required under existing UIC regulations. These plans include a monitoring and testing plan, an AoR and corrective action plan, and a post

- injection site care and site closure plan. The requirement for additional plans is intended to provide the Director the opportunity to assess proposed project operating procedures, and addresses GS requirements that are seen to be site

- specific (e.g., what monitoring techniques will be used). In addition, these plans are intended to establish an ongoing dialogue between the operator and the perm itting authority which is more substantial than that required for other classes of injection wells. ”

In EPA’s costs analyses, it appears that only costs associated with the incremental monitoring and testing plan were considered.

2 Advanced Resources International, Remediation of Leakage from CO 2 Storage Reservoirs

, IEA/CON/04/108, Report prepared for the IEA Greenhouse Gas R&D Programme, January 17, 2007October 17 , 200 8

4 Financial Responsibility R equirements

The proposed rule states:

“Today’s proposal would require that owners or operators demonstrate and maintain financial responsibility, and have the resources for activities related to closing and remediating GS sites. EPA is proposing that the r ule only specify a general duty to obtain financial responsibility acceptable to the Director, and will provide guidance to be developed at a later date that describes recommended types of financial mechanisms that owners or operators can use to meet this requirement.”

Obviously, since these requirements are not specified in the rule, they were not explicitly and quantitatively considered in the EPA cost. These costs will be a very important factor in deciding whether GS projects are pursued. At least som e discussion of the uncertainty associated with these costs, and the potential implications associated with this uncertainty on EPA’s conclusions , at a minimum, is warranted.

Site characterization costs considered in the EPA cost analysis do not include

an y costs for delineation wells

. For any target formation for GS that has not been extensively characterized by a large

number of wells ( such as deep saline aquifers, in contrast to the generally relatively well

defined depleted oil and gas fields), some wel ls will most likely need to be drilled to better understand the geology at or very near where the injection will take place. In many target formations, the information required for proper site characterization (cross sections, performing inter

- well seismi c, the acquisition of geochemical, geomechanical, and geophysical information, the relative location of the target injection zone and USDWs, characterization of the confining system, etc. ) will require drilling additional some wells. In fact, this could o ften involve drilling several wells to understand both vertical and areal heterogeneity in the vicinity where injection will take place. EPA’s cost analysis appears to conclude that no well drilling will take place as part of the geologic

characterization of the GS site.

Perhaps it is EPA’s assumption that the monitoring wells assumed under their characterization of monitoring costs will serve that purpose. If that is the case, then that

needs to be made clear.

Labor rate assumptions for engineers in the E PA cost analysis are much too low

. For most labor related activities assumed in the EPA cost analysis, it was assumed that tasks would be performed by either geologists or engineers. The geologist’s hourly labor rate was assumed to be $106.21 per hour, w hile the engineer’s hourly labor rate was assumed to be $53.52 per hour. Assuming 2,080 hours per year (including vacation), and a overhead markup ranging from 2.0 to 2.5, would result in a “representative” geologist’s salary of $88,000 to $111,000 per ye ar, and a “representative” engineer ’ s salary of $44,000 to $56,000 per year

.October 17 , 200 8

5 The American Association of Petroleum Geologists (AAPG) performs an annual salary survey of its members. 3 Based on this survey, if one assumes that the geologists performing the a ssignments have five years of experience or less, the assumed labor rates or geologists are reasonable. However, it is important to note that in the last 3 years, these salaries have risen by 35%.

Because of the similarities in the engin eering tasks associ ated with GS and those associated with developing and producing oil and gas, it would be reasonable to assume that most engineering tasks associated with GS would be preformed by individuals trained as petroleum engineers. The EPA cost analyses assume that these would be performed by geologic or mining engineers.

T he Society of Petroleum Engineers also performs an annual survey of its members, the last one conducted in September 2007. 4 The result of this survey shows that the mean annual salary of petrole um engineers in the U.S. was nearly $134,000. The average annual salaries for petroleum engineers with 0

- 10 years of experience were a little over $92,000. Of the various types of petroleum engineering categories considered in the survey, reservoir engine ers (the most likely types to be involved in GS site characterization, reservoir modeling, and monitoring types of activities) where the second high est paid category (behind finance /administration), with average annual

salaries for those 0

- 10 years of exp erience being a little less that $100,000.

Based on this, it seems that the labor rate assumptions for engineers in the EPA cost analysis were much too low , perhaps by a factor of two or more. (The assumed labor rate for engineers in EPA’s cost analyses ar e somewhat low even for mining engineers with some experience. 5

, 6 ) Since a large number of tasks are assumed to be performed by engineers in EPA’s assessment, this could have a substantial impact on their overall cost impact characterization , perhaps on t he order of about $60,000 per GS site.

Injection well d rilling cost assumptions in the EPA costs analysis are reasonable based on today’s conditions, but may not properly reflect recent increases in costs, as well as, importantly, the situation where deman d for well drilling services in the GS industry expands dramatically , perhaps increasing costs correspondingly.

The most expensive activity likely to be associate d with GS will be the costs associated with drilling injection wells, along with associated w ells required for monitoring and site

characterization . EPA assumes that the costs associated with just drilling injection wells can range from $210 to $280 per foot for wells typically drilled to a depth of on the order of 9,000 feet. Including all cost s associated with well drilling and completion increase s the range to from $280 to $320 per foot for a 9,000 foot well.

3 http://www.aapg.org/explorer/salarysurvey.cfm

4 h ttp://www.spe.org/spe

- app/spe/career/salary_survey/index.htm

5 http://www.bls.gov/oco/ocos027.htm#projections_data

6 http://www.payscale.com/research/US/Job=Mining_Engineer/SalaryOctober 17 , 200 8

6 According to the latest drilling cost survey by the American Petroleum Institute (for 2006) : 7

The average costs of drilling and completi ng wells in the U.S. (not including sidetrack wells) was $378 per foot. The average well depth in the U.S. was 5,560 feet.

The average well cost for all onshore wells in the 7,500 to 10,000 foot depth category was $2,660,000. The average depth of wells in this category was 8,722 feet. This then equates to an average cost of about $305 per foot.

As another point of reference, Advanced Resources has drilled a GS well associated with a demonstration project in Mississippi, and is in the process of developing an AFE for a new well. Based on this experience:

A recent well drilled to 14,500 feet cost a little over $3,200,000, or about $215 per foot.

The drilling and completion costs estimated for a planned new injection well to be drilled to 10,000 feet would be on the order of $1,800,000, or about $175 per

foot.

Based on all this, EPA ’s assumed injection well costs, on average, are within the range

associated with recent well drilling costs.

However, it is important to note that the 2006 API drilling cost survey shows that drilling

costs , on average, nearly doubled between 2003 and 2006, and that trend has

continued after 2006

. Moreover, if demand for drilling wells associated with GS increases dramatically, causing competition for drilling rigs between oil and gas exploration and production and GS, drilling costs are likely to rise even more, perhaps substantially. This should be at least noted, if not accounted for, in EPA’s cost

assessment.

Injection well cost assumptions in the EPA costs analysis appear not t o reflect all

of the additional requirements on well construction that the proposed regulations may require , in particular, the potential costs of

. As described above, while EPA’s drilling cost assumptions appear consistent with current well drilling and completion costs, the proposed regulations may require substantial enhancements to standard drilling requirements. For example, the proposed

rule states:

“Due to the buoyancy of CO 2 , today’s proposal includes enhancements to typical deep well construction procedures to provide additional barriers to CO 2 leakage outside of the injection zone. The proposal would require that surface casing for GS wells be set through the base of the lowermost USDW and cemented to the surface. The long

- string casing would be cemented in place along its entire

7 American Petroleum Institute, 2006 Joint Association Survey on Drilling Co sts , April 2008October 17 , 200 8

7 length. GS wells would also be constructed with a packer that is set opposite a cemented interval, at a location approved by the Director.”

It is not clear that the costs of all of these additional requirements were consi dered in
EPA’s cost assessment.

Moreover, the proposed rule recognizes that under some circumstances, fracturing of the injection zone may be necessary to allow sufficient injectivity of CO 2 (provided a specified set of conditions are met). This will be p articularly true for very deep and low permeability aquifers. No consideration of such fracturing costs is apparent in EPA’s cost analyses.

EPA appears not to consider the costs of surface equipment associated with CO 2 injection operations

In addition to the Injection wells, additional surface equipment can often be associated
with CO 2 injection operations. These costs include CO 2 storage vessels, high pressure pumps and vaporizers, distribution/production header s, and CO 2 distribution lines when multiple injection wells are needed

. It is not apparent that all of these costs are i ncluded

in the EPA costs estimates. This would result in an underestimate of on the order of $60,000

- $70,000 per well. In addition, many sites would require additional compressi on, and perhaps, substantially more extensive piping infrastructure; costs also not apparently considered in EPA’ s analyses . If this is the case, the cost underestimate could be substantially greater.

EPA assumptions that the cost analyses be based on the assumption that there will be no new climate change regulations appears inconsistent with the rationale

for the proposed GS rule.

EPA’s cost analyses are based on an anticipated level of GS activity in the United States under the existing regulatory condit ions, as per EPA guidelines on economic analysis. In this baseline analysis, EPA assumes that there will be no new national climate change regulations. Based on this assumption, EPA assumed there will be only 22 projects that would be affected by the propo sed GS rule. These projects include 12 anticipated DOE pilot projects, 3 projects proposed by DOE under the restructured FutureGen program, and 7 anticipated projects to be developed under state and regional incentive programs. 8

EPA does recognize that alt ernative assumptions about the future deployment of projects could dramatically change the potential costs of the proposed rule, 9 and performed a sensitivity analysis on this assuming a 50% increase in the number of projects.

8 Environmental Protection Agency, “Cost Analysis for the Proposed Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Proposed GS Rule)” Office of Water (4606

- M) July 2008 (pp. 3

- 4 to 3

- 5)

9 Ibid, p 5

- 33October 17 , 200 8

8 Nonetheless, this appears to b e somewhat inconsistent with the primary rationale for the rule. In the introductory discussion in the proposed GS rule, EPA describes the important role that GS can play in helping to mitigate global greenhouse gas emissions,

and states that :

“CCS techno logies could potentially represent a significant percentage of the cumulative effort for reducing CO 2 emissions worldwide.”

Moreover, the draft of the proposed GS rule goes on to say:

“ Establishing a supporting regulatory framework for the future develop ment and deployment of CCS technology can provide the regulatory certainty needed to foster industry adoption of CCS, which is crucial to supporting the goals of any proposed climate change legislation. ”

However, despite this rationale, the EPA cost analys es basically assume that no new GS projects other than those already proposed would result from the implementation of the proposed rule.

If this is in fact the case, it inevitably leads to the question: Why issue the proposed rule in the first place? All of the proposed projects assumed in the baseline are in the process of being pursued under existing regulatory authorities; and are not necessarily dependent on the promulgation of a new GS rule to be pursued.Letter ID: 0170 Commenter: Kyle Isakower Organization: American Petroleum Institute

Letter ID: 0170 Comment ID: 24117 Letter Lines: 49 to 58

Comment Code: 1200 1.1 General comments about the rulemaking

Comment: API commends EPA on their effort in draf ting rules for the long- term storage of carbon dioxide. API is very supportive of the fact that EPA has recognized the integrity of the existing regulatory framewo rk for CO2-based enhanced oil and gas recovery, of EPA's recognition that storage may occur during activities conducted under a Class II permit without requiring the well to obtain a Class VI permit, of the amount of flexibility operators have in meeting the requirements in most parts of the proposed rule, and of the use of performance-based st andards aimed at protecting underground sources of drinking water (USDWs).

API also appreciated EPA extending the co mment period. During that time, API has

Individual Response: EPA acknowledges the comment. EPA r ecognizes that the oil and gas industry has decades of experience injecting CO 2 for the purpose of EOR. The GS rulemaking builds upon existing experience and knowledge about safe injection practices in EOR and other injection industries, with tailored requirements that address the unique na ture of CO2 injection for GS. Please see the remainder of EPA's responses to this comment for further details. For additional information on EPA's final regulato ry approach, please see the final rule and preamble, including the discussion of the repermitt ing of Class II EOR wells for GS, as well as the rulemaking docket.

Letter ID: 0170 Comment ID: 24118 Letter Lines: 75 to 79

Comment Code: 1210 1.1.1 Comments about the proposed rule

Comment: API has serious concerns with several se ctions of the proposed rule, including the lowermost USDW restriction, the 50-year post-injec tion site care requirement, the well construction a nd operation requirements and the definitions of Geological Sequestration Project and Area of Review which we

ddress below. API also offers detailed revisions to address these issues and

Individual Response: EPA acknowledges the comment. Pleas e see the remainder of EPA's responses to this letter for further details.

Letter ID: 0170 Comment ID: 24119 Letter Lines: 84 to 91

1Comment Code: 1210 1.1.1 Comments about the proposed rule

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment)

Comment: API offers many technical clarifications to the rule based on industry's experience with well design, constructi on, and operation. Some are minor clarifications but others are important revisions. For example, EPA is proposing

the use of down-hole shut-off valves (see proposed §146.88(e) at 73 FR 43539), saying they would "isolate th e injectate below USDWs, rather than just below the surface" (73 FR 43511) when in fact, down-hole shut-off valves would not actually address this concern since they ar e not designed to provi de the type of isolation envisioned by the EPA.

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. However, the Agency believ es that offshore Class VI wells present unique construction and operational conditi ons, including isolation from shorelines and the need to construct wells through the water column and the subsurface, which may delay response time in

the event of well difficulties. Th e rule requires, at §146.88(e)(3), that owners or operators of

offshore wells within State territorial waters install automatic down-hole shut-off systems. EPA believes that these requirements at §146.88(e) ensure that proper precautions are taken to prevent subsurface fluid movement and ensure protection of USDWs.

EPA clarifies that down-hole shut-off devices are cu rrently used in situa tions where loss of well integrity could result in damage to the well or harm to humans (e.g., ne ar high-density population areas, or in onshore acid gas inj ection; IEA, 2003). EPA has identi fied examples of documented logging techniques, including ultr asonic and temperature logs, th at can be performed with an automatic down-hole device emplaced (Julian et al., 2007; Somaschini et al., 2009). They are also used in high pressure, high temperature onshore wells and in permafrost areas.

Letter ID: 0170 Comment ID: 24120 Letter Lines: 93 to 101

Comment Code: 1210 1.1.1 Comments about the proposed rule

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82)

Comment: EPA should be aware that some provisions seem to be based on data and information that would actually be generated by the permitted activity and therefore would not be available at the time of submittal of the permit application. For example §146.82(c) requests data from wells that cannot be drilled until the permit is r eceived. EPA proposed rules appear to contemplate delineation and evaluation activities prior to submittal of an application for GS wells/projects. It is not clear to API under what authority and regulatory

framework these activities would be conducte d since most Class VI projects will

2not be oil and gas related and so woul d not fall under oil and gas rules.

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.

Letter ID: 0170 Comment ID: 24121 Letter Lines: 103 to 113

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost

USDW

Comment: Lowermost USDW Restriction

EPA's proposal to restrict injection to fo rmations below the lowermost USDW is not necessary for the protection of USDWs and would remove a significant number

of viable formations from consideration as GS sites. Industry has shown that it can operate CO2 injection wells in an EOR context without endange ring USDWs that are located below the injection zone. An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW be low the injection zone. Moreover, under the proposed rule, there are other measures that would provide real assurance of formation integrity and require operators to demonstrate that their project will not endanger USDWs, making the lowermost USDW restriction unnecessary.

Individual 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 inject ion into non-USDW formations above and/or between USDWs. Additionally, the final GS rule doe s not categorically preclude or prohibit injection into any type

of formation.

EPA believes that these requirements will ensure USDW protection while providing flexibility to UIC program Directors and owne rs or operators who undertak e CO2 injection for GS. The

3Agency 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 highquality water remains available in sufficient quantities to supply dr inking water needs.

For additional information on the waiver approa ch, please see the final rule and preamble, as well as EPA's responses to comments on the No tice of Data Availability and Request for

Comment.

Letter ID: 0170 Comment ID: 24122 Letter Lines: 115 to 137

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

Comment: 50-year Default Post-Injection Site Care

EPA should also reconsider its propo sed 50-year default period for post-injection site care. EPA offers no ra tionale for this arbitrarily-selected period of 50 years. Establishing a fixe d and unusually long time period, even with the Director discretion provided, may create a significant barrier for operators considering entr y into CCS operations. Crite ria for determining the period for post-injection s ite care should be performa nce-based and a function of the site specific characteristics of a project such as proj ect size, geologic factors, and relative risk of the project. Clear guide lines also need to be established regarding when operators have met the performance standards that determine site closure. Specifically, th e standard that the project no longer poses an endangerment to USDWs needs to be defined using reas onable risk-based

criteria.

A related concern is that EPA is propos ing imposition of financial assurance requirements for activities that may occur more than 50 years in the future, with requirements to be satisfied at the time of permitting. EPA should carefully examine whether at this time, or at the time of permitting, the cost of such activities can be accurately es timated and assumed to be relatively accurate going forward. If not, financial a ssurance is no better than a guess, and serves only to introduce significan t uncertainties into project economics and project finance.

Individual Response: EPA disagrees that a post-injection si te care timeframe of 50 years is arbitrary. EPA proposed a default post-injection site care timeframe of 50 years based on a review of research studies, indus try reports, and existing environm ental programs. This analysis was included in an EPA-prepared background docume nt that is available in the federal docket,

4titled "Computational Modeling of Underground Injection of Carbon Dioxide for Determination

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

assessed various default timeframes based on additional review of research studies and evaluation of public comments. While numerous commenters suggested th at EPA shorten the monitoring timeframe, none of the commenters provided sufficie nt data or other evidence to warrant a change in the proposed timeframe. Wh ile the 10- or 30-year timeframe suggested by some of these commenters may be within the ti meframe suggested in some studies, EPA believes that the potential risks of endangering USDWs w ill likely not decline within these timeframes and available data, including data submitted by commenters, do not support a different default

timeframe. However, EPA recognizes that alternative timef rames may be appropriate under limited, specific circumstances. For this reason, the Class VI rule offers owners or operators flexibility regarding

the duration of the PISC timefra me by: (1) allowing the Direct or discretion to shorten or lengthen the PISC timeframe during the PISC pe riod based on site-specific data, pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator to demonstrate, based on substantial data during the permitting process, that an alternative PISC timeframe may be appropria te if it ensures non- endangerment of USDWs pursuant to requirements at §146.93(c). EPA believes that a 50 year pos t-injection site care timeframe represents a reasonable and protective monitoring period and available data, including data submitted by commenters, do not support a different default timeframe. Furthermor e, EPA believes that a 50-year default postinjection site care timeframe, as required at §146.93(b)(1), is not overly burdensome, does not exaggerate the risks associated with GS, is consistent with other environmental programs, and sufficiently protects USDWs from endangerment.

EPA adds that the purpose of the GS rule is not to incentivize the use of GS; rather, the purpose of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.

EPA recognizes that there are chal lenges associated with assuring funding for activities that will occur far in the future. However, the Agency be lieves 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.

Letter ID: 0170 Comment ID: 24123 Letter Lines: 124 to 128

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations

Comment: factors, and relative risk of the project. Clear guide lines also need to be established regarding when operators have met the performance standards that determine site closure. Specifically, th e standard that the project no longer poses an endangerment to USDWs needs to be defined using reas onable risk-based

criteria.

5Individual Response: EPA believes that many site-speci fic factors will influence the determination of when the CO2 plume and pressu re front no longer pose a risk of endangerment to USDWs, and therefore is not defining the criteri a in the final rule. It is for this reason that EPA believes that individual UIC Directors, in c onsultation with operators, will be in the best position to determine whether additional post-inje ction site care is needed. EPA expects this

decision to be made based on relevant site data and in consultation with all potentially impacted parties.

The post-injection site care requi rements in the final GS rule incorporate a combination of a fixed timeframe and a performance standard ap proach. The final GS rule offer owners or operators flexibility regarding th e duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthe n the PISC timeframe during th e post-injection period based on site-specific data, pursuant to requirements at §146.93(b); or (2) a ffording the Director discretion to allow a Class VI well owner or operator to demonstrate, during the permitting process based on substantial data, that an alternative PISC timeframe may be appropr iate if it ensures nonendangerment of USDWs pursuant to requirements at §146.93(c). 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 could plug injection and monito ring wells; demonstrate the appropriateness of an alternative post-inject ion site care time frame; perform post-injection monitoring; demonstrate non endangerment; and pe rform site closure act ivities. The guidance will be available at http://water.epa.gov/t ype/groundwater/uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 24124 Letter Lines: 130 to 137

Comment Code: 5436 2.9.1.3 Allowing separate financial demonstrations for plugging and abandonment and post-injection si te care (seeking comment)

Comment: A related concern is that EPA is propos ing imposition of financial assurance requirements for activities that may occur more than 50 years in the future, with requirements to be satisfied at the time of permitting. EPA should carefully examine whether at this time, or at the time of permitting, the cost of such activities can be accurately es timated and assumed to be relatively accurate going forward. If not, financial a ssurance is no better than a guess, and serves only to introduce significan t uncertainties into project economics and project finance.

Individual Response: EPA recognizes that there are challenges associated with estimating costs

for activities that will occur far in the future. However, the Agency believes that owners or operators must demonstrate that financial resources are availabl e to plug the injection well and provide post-injection care at the time the Class VI well is permitted. EPA clarifies at §146.85(a)(6) that, prior to obtaining a Class VI permit, an owner or operator may demonstrate financial responsibility by using one or multiple qualifying financial instruments for specific GS

6activities, thereby realizing greater flexibility and cost savings fr om this regulation. In the event that the owner or operator combin es more than one instrument for a specific GS activity (e.g., well plugging), such combination must be limited to instruments that are not based on financial strength or performance (i.e., self-insurance or performance bond) , such as, trust funds, surety bonds guaranteeing payment into a trust fund, letters of credit, escrow account , and insurance. In this case, it is the combination of instruments, rather than the single instrument, which must provide financial responsibility for an amount at least equal to the current cost estimate.

EPA believes that it is important to periodically update cost estimates that support financial responsibility determinations. The final GS rule , at §146.85(c), requires the owner or operator to provide annual updates to the cost estimate to account for any amendments to the AoR and corrective action plan, the injection well plugging plan, the PISC and site closure plan, and the emergency and remedial response plan. Owners or operators must also ad just the estimates for inflation annually under §146.85(c)(2). EPA adds that the Director can also require the owner or operator to provide an adjustment of the cost estimate if the Director determines that the original demonstration is no longer adequa te, as specified at §146.85(e).

In order to assist owners or operators and financial instituti ons in achieving accurate cost estimates for all GS activities, EPA plans to i ssue financial responsibil ity guidance that will include a discussion of how to estimate costs, in cluding how best to adjust cost estimates for inflation to account for the long- term nature of GS projects, in its guidance on meeting financial responsibility requirements for Class VI wells. Th is guidance will be available on EPA's website at http://water.epa.gov /type/groundwater/uic/wells_sequestration.cfm.

EPA agrees that GS technologies and cost estima ting methods are likely to change and improve as GS is deployed nationwide. However, EPA be lieves that past injec tion practices provide a good foundation for estimating the necessary costs and demonstrating financial responsibility. EPA envisions that financial responsibility updates required at the time of AoR reevaluation or at other frequencies specified by the Director will provide opportunities to refine the cost estimates and adjust the financial responsibil ity instruments as appropriate.

Letter ID: 0170 Comment ID: 24125 Letter Lines: 139 to 159

Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 146.86)

Comment: Class VI Well Construction and Operation

EPA should also reconsider its propo sed well construction and operation requirements which are much more prescrip tive and rigorous than necessary and do not reflect industry's 35-plus years of demonstrated success in injecting CO2 under the Class II UIC program. The buoyancy, corrosiveness in the presence of water, and anticipated volumes of CO2 do not justify the Class I hazardous well construction and operating requirements th at EPA is proposing. The Class II EOR wells constructed for CO2 injection proj ects - and their ope rating practices -

have an excellent record of mechanical integrity and protec ting USDWs. Recent

7research by the University of Texas, Bur eau of Economic Geology presented at the Department of Energy's Regional Partnershi p meeting in Pittsburgh, PA in October 2008 demonstrates that 35 years of CO2 in jection operations at the SACROC field in Texas have not impacted the USDWs in the area.

Furthermore, some of the proposed requirements - such as cementing the long string casing to surface and use of down- hole shut-off valves - are not only unnecessarily burdensome, but might also interfere with operations, may not serve their intended purpose, and could in troduce unintended risks. For example, cementing the longstring casing to surface seals off access to the annulus which

could otherwise be used to monitor subsur face formations for potential leakage.

Individual Response: EPA disagrees that the well construction standards for Class VI wells are too stringent. Instead, the cons truction requirements at §146.86 provide an appropriate and necessary level of protection from endangermen t to USDWs that is based upon the existing UIC framework for deep wells. The new tailored appro ach was designed to addr ess the general risks deep injection may pose to USDWs and was tailored specifically to address the unique nature of CO2 GS (i.e., including large injection volumes, the relative buoya ncy of CO2, its corrosivity in the presence of water, the potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations). EPA a dds that promoting GS or carbon management efforts is outside the scope of the GS rule making, which focuses on protecting USDWs from endangerment.

EPA does not believe that the cementing re quirements at §146.86 would prevent annulus monitoring. Cementing of deep wells has been pe rformed successfully in the past by owners or operators of Class I hazardous and Class I municipa l waste disposal wells. Some of these wells, which must meet the same cementing and casin g requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemen ted in a manner that ma intains integrity and allows for all required well te sting, operation, and remediatio n (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing gu idance 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: 0170 Comment ID: 24126 Letter Lines: 154 to 157

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment)

Comment: Furthermore, some of the proposed requirements - such as cementing the long string casing to surface and use of down- hole shut-off valves - are not only unnecessarily burdensome, but might also interfere with operations, may not serve their intended purpose, and could in troduce unintended risks. For example,

Individual Response: As described above, EPA will not require automatic down-hole shut-off

devices for onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from endangerment. Instead, the final rule , at §146.88(e)(2), requires that owners or

8operators of onshore Class VI wells install auto matic surface shut-off devices. The rule affords

Director's discretion to mandate automatic down-hole shut-off devi ces in onshore situations that may warrant their use. The rule requires, at §146. 88(e)(3), that owners or operators of offshore

wells within State territorial waters inst all automatic down-hole shut-off systems.

Letter ID: 0170 Comment ID: 24127 Letter Lines: 154 to 159

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

Comment: Furthermore, some of the proposed requirements - such as cementing the long string casing to surface and use of down- hole shut-off valves - are not only unnecessarily burdensome, but might also interfere with operations, may not serve their intended purpose, and could in troduce unintended risks. For example, cementing the longstring casing to surface seals off access to the annulus which

could otherwise be used to monitor subsur face formations for potential leakage.

Individual Response: EPA does not believe that the cem enting requirements at §146.86 would prevent monitoring, operation, and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity an d allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additi onal 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/gr oundwater/uic/wells_se questration.cfm.

Letter ID: 0170 Comment ID: 24128 Letter Lines: 161 to 190

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: Differentiating Applicability of Cl ass II versus Class VI Permits

API supports the concept embodied in the pr eamble that injection of CO2 for the purposes of enhanced oil and gas recovery in producing wells, even if production ceases for a period, will continue to be permitted under the Class II program (73 FR 43502). API would like to see EPA remain committed to the intent of the language in the preamble and EPA's interpretation of that language as expressed during API's meeting with EPA on October 27 th ,that CO2 storage in association with EOR activities proceeds under the Class II program.

As mentioned earlier, this is an area that has been discussed by the MSDG. The Group proposes a "bright line" for disti nguishing Class II EOR "business as usual" from other activities (see §146.5(b) {4)). API proposes that wells used

9for GS in oil and gas reservoirs that do not meet the criteria proposed for §144.6{b)(4) be regulated under the Class II pr ogram since it would facilitate EOR operations transitioning to GS unde r the same regulatory jurisdiction.

The approach is not radically different from the approach proposed by EPA (as amended by API) for transitioning from EOR to Geologic Storage (see comments regarding §146.81(c) in API's line-by line ed its to the proposed rule). Even if

EPA's final decision is to establish a new well subclass under the Class II program, API's comments on the proposed Clas s VI rule remain relevant and should be addressed by EPA.

Again, details of what would be required of wells used for GS in oil and gas

reservoirs that do not meet the criter ia proposed for §144.6(b){4) are to be worked out during future discussions of the Multi-Stakeholder Discussion Group (MSDG). However, API offers language whic h is consistent with suggestions API had developed before discussions with th e MSDG began (see API's comments on §146.25).

Individual Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas recovery should remain under the Cl ass II Program. EPA rec ognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of EOR, and that sites used for ER may be suitable for GS and may be among the first GS sites.

However, the Agency disagrees that wells inje cting CO2 for the primary purpose of long-term storage should be regulated under Class II requirements. The Agency believes that the nature and risks of CO2 injection for the primary purpose of long-term storage pose different risks than injection for the primary purpose of ER, and theref ore has developed new Class VI regulations to address these unique risks. For example, the volu me of CO2 anticipated to be injected for longterm storage is significantly greater than for ER operations. Reservoir pressure conditions will also be different, with Class VI injection opera tions involving large vo lumes of CO2 and likely having higher pressures within their storage formations th an Class II ER projects.

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. For more information, please see the discussion on transition of Class II wells in the preamble to the final GS rule.

Letter ID: 0170 Comment ID: 24129 Letter Lines: 192 to 204

Comment Code: 5610 2.11.1 Allowing partial primacy for Class VI wells (seeking comment)

10Comment: State Primacy

API contends that states and tribes sh ould play a key role in managing CCS projects going forward. Accordingly, states should be permitted to seek primacy for the Class VI program, even in the abse nce of primacy for other well classes (partial primacy). Numerous states have decades of experience regulating CO2 injection through Class II programs, and t hose states in particular may have much to offer in the context of Class VI wells. A critical component of the primacy delegation process is for EPA to ensure that States will be adequately

funded to deal with the increased burdens associated with managing the Class VI program. Conversely, some states may not have formations with the necessary geologic characteristics to allow GS a nd so may want to pass on obtaining primacy for this program.

Individual Response: EPA agrees that states should be al lowed to obtain primacy for Class VI wells independently of other well classes, and wi ll allow independent primacy for Class VI wells under §145.1(i) of the final GS rule. In the past , EPA has not accepted UIC primacy applications

for individual well classes unde r Section 1422 of SDWA. In other words, if a State wanted primacy for Class I wells, the State would also ne ed to accept responsibilit y for Class III, IV, and V wells. This policy was intended to encourage states to take full responsibility for UIC programs, avoid duplication of efforts, and provide for administrative efficiencies.

However, given the potential for CCS (encom passing capture, transportation, and geologic sequestration) to be an important part of a na tional priority to address climate change, EPA believes that providing states the flexibility to obtain primacy for Class VI wells independently of other well classes can help foster effective management of CCS. EPA believes that allowing independent Class VI primacy may encourage states to take res ponsibility for implementation of Class VI regulations and provide for a more co mprehensive approach to managing CCS projects by promoting the integration of GS activities under SDWA in to a broader framework for managing CCS. Furthermore, GS operations involve ancillary activities (e.g., pipeline operations, pore space ownership, land use rights, and surface access) for which states can call upon other authorities that exist at the state leve l (but outside UIC author ity) to provide a more comprehensive CCS management approach.

EPA also believes that allowing states to apply only for Class VI primacy will shorten the primacy approval process for states. It is very im portant to note that this shift in policy allowing for Class VI primacy does not apply to a ny other well Class under Section 1422. EPA will continue to discourage applica tions for partial primacy for a ll other well types under Section

1422.

EPA recognizes that some stat es may not have appropriate geology for sequestering CO2, and

these states should be able to re tain primacy for other well classe s without incurring the cost and burden of adopting primacy changes to addr ess the new Class VI well requirements.

EPA clarifies that states should be able to obtain primacy for Cla ss VI wells independent of other

11well classes provided they devel op regulations that are at leas t as stringent as the minimum Federal requirements (e.g., permitting, inspec tion, operation, monitoring, and recordkeeping requirements) in the final GS rule. EPA believes that existing programs can adapt their expertise to the new requirements for Class VI wells and w ill be able to develop a primacy application for

Class VI wells under section 1422 of SDWA and en sure that their GS pr ograms integrate into national climate change priorities an d protect USDWs from endangerment.

EPA also acknowledges that there may be techni cal and administrative challenges including resource concerns, and will work closely with the st ates to assist them in resolving funding issues or acquiring the resources, pers onnel, and training needed to address the unique technical challenges associated with GS.

EPA will also incorporate Class VI wells into the UIC Program's grant allocation process. The

States/Tribes/Territories must also demonstrate th at they have adequate resources to implement the program through matching resources against those allocated by the UIC Program's grant allocation formula. Currently, primacy programs ar e required to meet a minimum of 25 percent matching requirement.

Letter ID: 0170 Comment ID: 24130 Letter Lines: 206 to 212

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling CO2 movement

Comment: Definition of Geological Sequestration Proj ect (GSP) and Area of Review (AoR)

EPA's definitions of GSP and AoR require alignment. Currently the GSP and AoR definitions c onfusingly use different wording to describe similar concepts. It is API's view that these defi nitions should be essentially the same. API offers language s in our detailed edits that achieve

this.

Individual Response: Based on review of all public comments on the AoR definition at 146.84(a), the Agency has modified it to read as follows: The region surrounding the geologic sequestration project where USDWs may be e ndangered by the injecti on activity. The area of review is delineated using computational mode ling that accounts for the physical and chemical properties of all phases of the injected CO 2 stream and is based on available site characterization, monitoring, and operational data. The definition in the proposed rule accounted for the varying physical and chemical propertie s of the CO2, including free-phase and waterdissolved CO2. The definition in the fi nal rule will continue to do so.

EPA is developing guidance on AoR and corrective act ion at GS Class VI s ites to assist owners or operators and Directors in evaluating requi rements and proposed AoR and corrective action plans under 146.84. The guidance describes EPA's reco mmended approaches for the data to be

considered in an initial AoR delineation, how to apply computat ional modeling to delineate the AoR, performing corrective action at GS sites, and, when appropriate, completing AoR

12reevaluations. The guidance will be available on EPA's web site at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

Letter ID: 0170 Comment ID: 24131 Letter Lines: 214 to 235

Comment Code: 5460 2.9.2 Comments on transfer of lia bility for long-term care

Comment: Long-term Responsibility

While API realizes the issue of long-term responsibility management for GS sites is beyond the scope of this rule, API f eels it is important to offer some comments on this topic. API believes long- term responsibility management for decommissioned carbon storage sites is an i ssue that should be defined early in the planning process for a carbon capt ure and storage (CCS) project. A management system that ensures the res ponsible entity is clearly identified, defines the scope of those responsibilities , and ensures the entity is properly funded is essential for sound project planning.

The recommended model is for the storag e site owner or operator to hold responsibility during the ope rational phases of the proj ect through a reasonable post-closure monitoring period. With adequa te demonstration of site integrity and stability, responsib ility for the long term stewar dship of the site should be transferred to a public entity (government, public trust, or other competent authority). Prior to transfer of this re sponsibility the site owner or operator should demonstrate the following: 1) comp liance with the requi rements of all applicable regulations, permits, and a pprovals relevant to the long term integrity of the site and 2) site inte grity by reasonable and proven surface and subsurface monitoring for an appropriate period of time after the completion of injection operations or any subs equent remediation operations.

Individual Response: EPA agrees that the issu e of long-term liability management for GS sites is outside the scope of this rulemaking.

Under the final GS rule, once an owner or ope rator has met all regulatory requirements under

Part 146 for Class VI wells and th e Director has approved site cl osure pursuant to requirements at §146.93, the owner or operator will generally no longer be subject to enforcement for regulatory noncompliance. Furthermore, thei r financial instrument as required under §146.85 will be released if it was not used. However, ev en if a site closure is approved under §146.93, an owner or operator may be held liable for re gulatory noncompliance (inc luding violation of 40 CFR 144.12) in certain circumstances. For example, an owner or operator may be held liable for regulatory noncompliance even after site clos ure was approved if the Director relied on erroneous information (e.g., erroneous modeling data) provided by the owner or operator when approving site closure.

Separate from EPA’s authority to enforce regul atory compliance, an owner or operator may be

13subject to a §1431 response orde r even after proper site cl osure is approved under §146.93. Under §1431 the Administrator may require an ow ner or operator to take necessary response

measures if he or she receives information that a contaminant is present or is likely to enter a public water system or an USDW, which may pres ent an imminent and s ubstantial endangerment to the health of persons, and the appropriate Stat e and local authorities ha ve not acted to protect the health of such persons. Th e action may include issuing admi nistrative orders or commencing a civil action for appropriate relief against the ow ner or operator of a Class VI well. If the owner or operator fails to comply with the order, they may be subject to a civil penalty for each day in

which such violation occurs or failure to comply continues.

Furthermore, after site closure an owner or ope rator may remain liable under tort and other remedies, or under other federal statutes includi ng, but not limited to, Clean Air Act, 42 U.S.C. §§ 7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. EPA does not have authority to transfer SDWA or other legal liability for Class VI wells to the State or federal government or a third-party fund. See the final rule preamble for further discussion of EPA's final approach.

Letter ID: 0170 Comment ID: 24132 Letter Lines: 239 to 245

Comment Code: 1250 1.1.1.4 Flexibility is needed (p erformance-based standards)

Comment: API shares the same goal as EPA: to de velop rules that facilitate the safe, secure longterm storage of CO2. API is concerned though that by being overly restrictive in designing the new well cla ss, the proposed rule will hinder the deployment of CCS and could have the unant icipated consequence of hindering the innovations that could improve both well security and perf ormance. CCS is likely to be of one of the core technologies th at could help to ensure that we can continue to produce the clean energy so ciety demands. API would be eager to

Individual Response: EPA agrees that permitting decisions for GS wells should be based on site-specific factors. The GS ru le requires owners or operators to submit, and Directors to consider, extensive site-specific data, specified at §146.82, to demons trate that a site is suitable for GS. Additionally, many of the permit require ments for GS wells are established through individualized site-specific pl ans for AoR and corrective actio n, testing and monitoring, and injection well plugging and post-injection site care and site closure. EPA adds that the final GS rule includes a balance of speci fic criteria to be met by the owner or operator and areas of

Directorial discretion and consider ations for how that discretion would be exercised. The Agency believes this balance allows for GS projects to be designed and permitted to address the unique, site-specific aspects of each project, while prov iding consistency in permitting across the U.S.

EPA clarifies that the Class VI GS requirements are designed to ensure that, where deployed, GS is conducted in a manner that protects USDWs fr om endangerment. Encouraging investment in CCS projects and facilitating deployment are outside the scope of the GS rulemaking.

14Letter ID: 0170 Comment ID: 24133 Letter Lines: 269 to 280

Comment Code: 1220 1.1.1.1 Terminology and definitions

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: [In this document, the text in all

CAPS denotes added text. For redline strike out version of this attachment see

PDF Docket ID EPA- HQ-OW-2008-0390-0170.]

Rule Provision: 144.3

API Comments: ENHANCED OIL RECOVERY (EOR) OR ENHANCED GAS RECOVERY (EGR) MEANS ANY ACTIVITY THAT USES FLUIDS, GASE S OR OTHER MEANS TO IMPROVE OR

INCREASE

EXTRACTION OF HYDROCARBONS.

Rationale: The definition of EOR is nece ssary to support further comments and

discussion below.

Individual Response: EPA included the following definition for Enhanced Oil or Gas Recovery in the preamble to the rule: typical ly, the process of injecting a fl uid (e.g., water, brine, or CO2) into an oil or gas bearing formation to recover re sidual oil or natural gas. The injected fluid thins (decreases the viscosity) and/or displaces small am ounts of extractable oil a nd gas, which is then available for recovery. This is also known as secondary or tertiary recovery.

Letter ID: 0170 Comment ID: 24134 Letter Lines: 282 to 312

Comment Code: 1220 1.1.1.1 Terminology and definitions

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 Code: 4400 2.4.4.3 Allowing injection above or between USDWs (seeking comment)

Comment: Rule Provision: 144.6

API Comments: Sections 144.6 - Classification of Wells: (b) Class II. Wells whic h inject fluids:... (4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC SEQUESTRATION IS

OCCURRING DURING OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL

OR NATURAL GAS PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE THAN

INSIGNIFICANT FUTURE

PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION AND (II)

15OPERATING PRESSURES ARE NO HIGHE R THAN REASONABLY NECESSARY TO

PRODUCE SUCH VOLUMES OR RATES; AND

(5) FOR GEOLOGIC SEQUESTRATION IN OIL AND GAS FORMATIONS AND WHERE

THE CRITERIA OF PARAGRAPH (B)(4) ARE NOT MET

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon dioxide STREAMS. beneath the lowermost formation containing a USDW WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2 STREAMS OCCURS DURING OR IN

CONNECTION WITH

EOR OR EGR ARE REGULATED UNDER CLASS II.

Rationale: Additionally, there should not be a blanket prohibition concerning injection above USDW’s or at specific dept hs. This is especia lly true given the possibility of changes in th e definition of a USDW to in clude formations greater than 10,000 parts per million Total Dissolved Solids. This requirement is not necessary for the protection of USDWs and would remove a vast number of viable

formations from consideration. Industr y has shown that it can operate CO2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent exam ple is the Salt Cree k EOR project in Wyoming, which has a USDW below the inject ion zone. Moreover, under the proposed rule, there are other measures that woul d provide real assura nce of formation integrity and require operators to dem onstrate that their project will not endanger USDWs, making the lowermos t USDW restriction unnecessary.

Individual Response: EPA did not make the suggested change . EPA clarifies that the final rule requires that injection for GS be into non-USDWs below the lowermost USDW; however, owners or operators may apply fo r a waiver from this requirem ent, as described in §146.95. For more information, see the disc ussion of waivers in the pr eamble to the final rule.

The Agency disagrees that wells injecting CO 2 for the primary purpose of long-term storage should be regulated under Class II requirements. The Agency believes that the nature and risks of CO2 injection for the primary purpose of long-term storage pose different risks than injection for the primary purpose of ER, and therefore has de veloped new Class VI re gulations to address these unique risks. For example, the volume of CO2 an ticipated to be injected for long-term storage is significantly greater than for ER opera tions. Reservoir pressure conditions will also be different, with Class VI injection operations i nvolving large volumes of CO2 and likely having higher pressures within thei r storage formations than Class II ER projects.

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.

16The 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. For more information, please see the discussion on transition of Class II wells in the preamble to the final GS rule.

EPA is developing guidance on transitioning 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 purpos e is oil and gas production, to Class VI, where the primary purpose is long-term storage of large volumes of CO2. The gu idance describes the recommended methods the Director may use to determine cha nges in risk to USDWs from projects, and how the Director may determine whether a project should be regulated within the Class II or Class VI UIC program. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 24135 Letter Lines: 301 to 312

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost

USDW

Comment: Rationale: Additionally, there should not be a blanket prohibition concerning injection above USDW’s or at specific dept hs. This is especia lly true given the possibility of changes in th e definition of a USDW to in clude formations greater than 10,000 parts per million Total Dissolved Solids. This requirement is not necessary for the protection of USDWs and would remove a vast number of viable

formations from consideration. Industr y has shown that it can operate CO2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent exam ple is the Salt Cree k EOR project in Wyoming, which has a USDW below the inject ion zone. Moreover, under the proposed rule, there are other measures that woul d provide real assura nce of formation integrity and require operators to dem onstrate that their project will not endanger USDWs, making the lowermos t USDW restriction unnecessary.

Individual Response: As described above, EPA agrees that it is not appropriate to set aminimum injection depth for GS projects and the Agency believes that a determination of sitesuitability for GS (i.e., that subsurface formati ons will receive and confine injected CO2) should be made on a site-specific basis. The GS rule , at §146.82, requires the owner or operator to provide extensive site- a nd project-specific information to the Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be contained within the injection formation, and that USDWs will be protected from endangerment.

Letter ID: 0170 Comment ID: 24136 Letter Lines: 314 to 324

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

Comment Code: 5700 2.12 Comments on the proposed durati on of Class VI permits (seeking

17comment)

Comment: Rule Provision: 144.36(a)

API Comments: (a) Permits for Class I and V wells shall be effective for a fixed term not to exceed 10 years. UIC Permits for Class II AND III and VI wells

shall be issued EFFECTIVE for a period up to the operating life of the facility. PERMITS FOR CLASS VI WELLS SHALL BE EFFECTIVE FOR THE PERIOD

THROUGH

SITE CLOSURE.

Rationale: Permits are necessary for Cla ss VI wells through the end of the post closure monitoring phase, which is consistent with the term site closure in the amended requirement.

Individual Response: EPA clarifies that the final GS rule sp ecifies that Class VI permits will be issued for the operating life of the facility and the pos t-injection site care period (144.36(a)). The rule also adds a requirement that the Director review each Class VI permit at least every five years to determine whether it should be modifi ed, revoked and reissued, terminated, or a minor modification made as provided in §§144.39, 144.40, or 144.41. The Director’s review will be informed by the owners’ or operato rs’ iterative reev aluation of the project. Specifically, the final rule includes a requirement that the AoR be reev aluated at least every five years, and also requires owners or operators to review and update the AoR and corrective action plan, the testing and monitoring plan, and the emergency and reme dial response plan th roughout the life of the project (146.84(e), 146.90(j), and 146.94(d)). Owners or operators must review each plan and identify necessary amendments or demonstrate to the Director that no amendment is needed. In

no case can reviews occur less often than once ev ery five years. The iterative process and subsequent plan reevaluations ensure that time and resources are committed to the most critical aspects of the permit in preven ting endangerment to USDWs.

Letter ID: 0170 Comment ID: 24137 Letter Lines: 326 to 342

Comment Code: 1220 1.1.1.1 Terminology and definitions

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 Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost

USDW

Comment: Rule Provision: 144.80

API Comments: b) Class II. Wells which inject fluids:...... (4 ) FOR ENHANCED

RECOVERY OF OIL OR NATURAL GA S WHERE GEOLOGIC SEQUESTRATION IS

OCCURRING DURING

OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR NATURAL GAS PROVIDED (I) THERE

IS REASONABLE EXPECTATION OF MO RE THAN INSIGNIFICANT FUTURE

18PRODUCTION VOLUMES

OR RATES AS A RESULT OF CARBON DI OXIDE INJECTION AND (II) OPERATING

PRESSURES

ARE NO HIGHER THAN REASONABLY NE CESSARY TO PRODUCE SUCH VOLUMES OR RATES; AND

(5) FOR GEOLOGIC SEQUESTRATION IN OIL AND GAS FORMATIONS AND WHERE

THE CRITERIA OF PARAGRAPH (B)(4) ARE NOT MET

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon

dioxide STREAMS. WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2 STREAMS

OCCURS DURING

OR IN CONNECTION WITH EOR OR EGR ARE REGULA TED UNDER CLASS II.

Rationale: See 144.6

Individual Response: As described above regarding the suggested edit at 144.6, EPA did not make the suggested change. The Agency disagr ees that wells injecting CO2 for the primary purpose of long-term storage should be regulated under Class II requirements.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment EPA has made many revisions to the GS Rule. See the final rule and preamble for further discussion on EPA's final appr oach to transitioning from Class II to Class

VI.

Letter ID: 0170 Comment ID: 24138 Letter Lines: 344 to 362

Comment Code: 1220 1.1.1.1 Terminology and definitions

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 Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost

USDW

Comment: Rule Provision: 146.5

API Comments: b) Class II. Wells which inject fluids:...... (4 ) FOR ENHANCED

RECOVERY OF OIL OR NATURAL GA S WHERE GEOLOGIC SEQUESTRATION IS

OCCURRING DURING

OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL OR NATURAL GAS PROVIDED (I) THERE

IS REASONABLE EXPECTATION OF MO RE THAN INSIGNIFICANT FUTURE

PRODUCTION VOLUMES

OR RATES AS A RESULT OF CARBON DI OXIDE INJECTION AND (II) OPERATING

PRESSURES

19ARE NO HIGHER THAN REASONABLY NE CESSARY TO PRODUCE SUCH VOLUMES OR RATES; AND

(5) FOR GEOLOGIC SEQUESTRATION IN OIL AND GAS FORMATIONS AND WHERE

THE CRITERIA OF PARAGRAPH (B)(4) ARE NOT MET

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon dioxide STREAMS. Beneath the lowermost formation containing a n underground source of drinking water (USDW). WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2

STREAMS OCCURS DURING OR IN CO NNECTION WITH EOR OR EGR ARE

REGULATED UNDER CLASS

II.

Rationale: See 144.6

Individual Response: As described above regarding the suggested edit at 144.6, EPA did not make the suggested change. The Agency disagr ees that wells injecting CO2 for the primary purpose of long-term storage should be regulated under Class II requirements.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment EPA has made many revisions to the GS Rule. See the final rule and preamble for further discussion on EPA's final appr oach to transitioning from Class II to Class

VI.

EPA clarifies that the final rule requires that injection for GS be into non-USDWs below the lowermost USDW; however, owners or operators may apply for a waiver from this requirement, as described in §146.95. For more information, see the discussion of waivers in the preamble to

the final rule.

EPA acknowledges that there are limited circum stances where injectio n above the lowermost USDW can be performed in a manner that pr otects USDWs from endangerment, as long as appropriate protections are in pl ace. However, EPA disagrees with the suggested addition to the regulation. The final GS rule at §146.95 establishes a pr ocess by which owners or operators can seek a waiver of the Class VI injection de pth requirements for in jection into non-USDW

formations above and/or between USDWs. It esta blishes: 1) requirement s specifying information that owners or operators must submit, and Dire ctors must consider, in consultation with PWSS Directors; 2) procedures for public notice of a waiver applic ation and for Director-Regional Administrator communication; 3) the waiver issu ance process; and, 4) additional requirements that apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements to ensure USDW protection above and below the injection zone.

Letter ID: 0170 Comment ID: 24139 Letter Lines: 364 to 382

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

20Comment Code: 2064 1.5.3.2 Grandfathering construction of Class II wells (seeking comment)

Comment: Rule Provision: 146.25 GEOLOGIC SE QUESTRATION IN OIL OR GAS

RESERVOIRS WITHOUT

ENHANCED RECOVERY OF OIL OR NATURAL GAS

API Comments: WELLS USED FOR GEOL OGIC SEQUESTRATION AND MEETING THE

CLASSIFICATION CRITERIA OF SECTION 146.5(B)(5) SHALL BE SUBJECT TO THE

FOLLOWING REQUIREMENTS: (A) EXISTING WELLS THAT MEET OR EXCEED THE CONSTRUCTION REQUIREMENTS OF § 146.22 SHALL BE SUBJECT TO PART 146, SUBP ART H [AS REVISED BY API] EXCEPT

SECTIONS

146.86 AND 146.87. (B) NEW WELLS MUST MET THE CONS TRUCTION REQUIREMENTS OF SECTION

146.22 AND ARE SUBJECT TO PART 146, SUBPART H [AS RE VISED BY API] EXCEPT SECTIONS 146.86

AND

146.87

Rationale: Details of what would be re quired of "Class IIB" wells are to be worked out during future discussions of the Multi-Stakeholder Discussion Group (MSDG). However, API offers this language which is consistent with changes API had suggested before discussions with th e MSDG began (see Section 146.81(c)). These suggestions are - as noted - conti ngent on EPA‘s adoption of API‘s changes to Part 146, Subpart H.

Individual Response: As described above regarding the suggested edit at 144.6, EPA did not make the suggested change. The Agency disagr ees that wells injecting CO2 for the primary purpose of long-term storage should be regulated under Class II requirements because Class II requirements do not address the unique risks pose d by GS while ensuring protection of USDWs from endangerment.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment EPA has made many revisions to the GS Rule. See the final rule and preamble for further discussion on EPA's final appr oach to transitioning from Class II to Class

VI.

Letter ID: 0170 Comment ID: 24140 Letter Lines: 386 to 397

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

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: API Comments: (b) This subpa rt applies to wells used to inject carbon dioxide

21EXCLUSIVELY for the purpose of geologic sequestration, i.e ., the long-term containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. IT IS RECOGNIZED THAT SOME ACTIVITIES

CONDUCTED UNDER CLASS II, INCLUDING CO2 BASED EOR OR EGR MAY SEQUESTER A

PORTION OF THE

CARBON DIOXIDE STREAM USED FOR EOR OR EGR. THIS SUBPART DOES NOT

APPLY TO

INJECTION OF A CARBON DIOXIDE STREAM FOR PURPOSES OF EOR OR EGR EVEN

THOUGH GEOLOGIC SEQUESTRATION OF CARBON DI OXIDE MAY OCCUR DURING OR IN

CONNECTION WITH

EOR OR EGR OPERATIONS AND/OR ACTIVITIES.

Rationale: See 144.6. Deleted "gaseous, liqui d or supercritical" because it was

added to the definition of CO2 stream.

Individual Response: As described above regarding the suggested edit at 144.6, EPA did not make the suggested change. The Agency disagr ees that wells injecting CO2 for the primary purpose of long-term storage should be regulated under Class II requirements.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment EPA has made many revisions to the GS Rule. See the final rule and preamble for further discussion on EPA's final appr oach to transitioning from Class II to Class

VI.

Letter ID: 0170 Comment ID: 24141 Letter Lines: 399 to 428

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

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: Rule Provision: 146.81(c)

API Comments: (c) This subpart applies to owners and operators of permit or

rule-authorized Class I industrial, Class II , or Class V experimental carbon dioxide injection projects who seek to apply for a Class VI geologic sequestration permit for their well or wells. If the Director determines that USDWs will not be endangered, such wells are exempt, at the Director‘s discretion, from the casing and cementi ng requirements at §§ 146.86(b) and 146.87(a)(1) through (3).

Rationale: The reference to Class II we lls in section 146.81(c) is no longer needed due to addition of 146.25 . However, if EPA were not to adopt section 146.25, API would suggest the following revisions:

22(c) This subpart applies to owners and operators of permit or rule-authorized Class I industrial, Class II WHO HAVE CE ASED AND WILL NO LONGER CONTINUE EOR

OR EGR OPERATIONS OR ACTIVITIES, 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, such wells are exempt, at the Director‘s disc retion, from the casing and cementing requirements at §§ 146.86(b) an d 146.87(a)(1) through (3). CLASS VI REQUIREMENTS. CLASS II WELLS PERMITTED FOR CO2 INJECTION

AND THAT HAVE DEMONSTRATED MIT ARE EXEMPT FROM THE REQUIREMENTS AT §§146.86 AND

146.87.

The language allows for the transition of Class II wells to Class VI operations. These wells should be allowed to inject CO2 for storage based on their history of sound performance under the Class II prog ram as demonstrated by MIT results. The language also allows the Director to exercise discretion to exempt other Class VI requirements.

Individual Response: As described above, EPA disagrees that wells injecting CO2 for the primary purpose of long-term storage should be regulated under Cla ss II requirements.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment EPA has made many revisions to the GS Rule. See the final rule and preamble for further discussion on EPA's final appr oach to transitioning from Class II to Class

VI.

Letter ID: 0170 Comment ID: 24142 Letter Lines: 430 to 443

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment Code: 3200 2.2 Proposed Area of Review and Corrective Action Requirements (40 CFR 146.84)

Comment: Rule Provision: 146.81(d) [Definition - Area of review]

API Comments: Area of review means the region surrounding the geologic Sequestration project that may be imp acted by the injection activity. The area

of review is based on com putational modeling that acc ounts for the physical and chemical properties of all ph ases of the injected carbon dioxide stream.

SUBSURFACE THREE-DIMENSIONAL EXTE NT OF THE CARBON DIOXIDE PLUME,

ASSOCIATED PRESSURE FRONT, AS WELL AS THE OVERLYING FORMATIONS AND SURFACE

AREA ABOVE THAT

DELINEATED REGION.

23Rationale: Defining the AOR based on the extent of the CO2 plume and its associated pressure front is a more dir ect approach, rather than the approach offered by the EPA. The EPA definition sugg ests that the computational approach defines the AOR rather than the potential risks of the injection activity.

Individual Response: EPA disagrees that the AoR definition needs to specifically include the overlying formations and surface area above the delineated region. The intent of the AoR, a long-standing concept within the UIC Program, is to delineate the surf ace area and all subsurface formations below it that may potentially be impacted by injecti on activity. Acceptable delineation models will provide predictions of CO 2 fate and transport, as well as changes in formation pressure in three dimensions as a func tion of time that can be used to delineate the subsurface storage site and the AoR. Although EP A disagrees with the commenter's suggested change, the Agency has carefully considered all comments on the AoR definition at 146.84(a) and modified it to read as follows: The regi on surrounding the geologic sequestration project where USDWs may be endangered by the injection activity. The ar ea of review is delineated using computational modeling that accounts for the physical and chemical properties of all phases of the injected CO2 stream and is base d on available site characterization, monitoring, and operational data. EPA believes that this defi nition is sufficiently broad and describes both the intent of the computational modeling and the relationship of th e AoR to areas that are subject

to the risks associat ed with injection.

Letter ID: 0170 Comment ID: 24143 Letter Lines: 445 to 458

Comment Code: 1220 1.1.1.1 Terminology and definitions

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

Comment: Rule Provision: 146.81(d) [Definitio n - Carbon dioxide stream]

API Comments: Carbon dioxide stream means carbon dioxide, IN ANY PHYSICAL STATE OR FORM, AND ANY ASSOCIATED substances derived from the that has been capt ured

from an emission source (e.g., a power plant), plus incidental associated

substances derived from the source mate rials and the capture process, and any, ITS PROCESSING, OR substances added to en able or improve the injection process. This subpart does not apply to any ca rbon dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261.

Rationale: Source of CO2 is not an issu e in the context of defining the CO2 stream. The rule applies to the inject ion of CO2 and should not address the origins of the materials since that is beyond the scope of this regulation. Original text would have precluded in jection of CO2 from some sources.

Individual Response: The final GS rule retains the defini tion of a CO2 stream as proposed. The GS regulation applies to injecti on of CO2 for the purpose of GS, regardless of the source of the CO2. It is beyond the scope of the GS rule and the UIC Program’s authority to require or set standards for upstream generators of CO2 or purification facilities . For purposes of GS, the UIC

24program’s authority under the SDWA is limited to ensuring that GS projects are sited, constructed, operated, and closed in a manner that protects USDWs.

Letter ID: 0170 Comment ID: 24144 Letter Lines: 460 to 466

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment: Rule Provision: 146.81(d) [Definition - Geologic sequestration]

API Comments: Geologic se questration means th e long-term containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. This term does not appl y to its capture or transport.

Rationale: Added to definition of carbon dioxide stream, so not needed here.

Individual Response: EPA disagrees with the suggested edit; the final definition of geologic sequestration at §146.81(d) reads as follows: “[T] he long-term containment of a gaseous, liquid, or supercritical carbon dioxide stream in subsur face geologic formations. This term does not apply to carbon dioxide cap ture or transport.”

The final definition of carbon di oxide stream also remains uncha nged. Carbon dioxide stream is defined at §146.81(d) as: “[C]ar bon dioxide that has been captu red from an emission source (e.g., a power plant), plus incidental associated s ubstances derived from the source materials and the capture process, and any subs tances added to the stream to enable or improve the injection process. This subpart does not apply to any carb on dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261.”

Based on its evaluation of all public comments and input on the proposed rule and the NODA and Request for Comment, EPA has made many revisions to the Cla ss VI GS rule. Please see the final rule and preamble for additional information.

Letter ID: 0170 Comment ID: 24145 Letter Lines: 468 to 486

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: Rule Provision: 146.81(d) [Definition - Geologic sequestration project]

API Comments: Geologic seque stration project means an in jection well or wells used to emplace a carbon dioxide stream beneath the lowermost formation containing a USDW INTO AN INJECTION ZONE EXCL USIVELY FOR THE PURPOSE OF GEOLOGIC SEQUESTRATION. It includes the s ubsurface three-dimensional extent of the carbon dioxide plume, associated pressure front, and displaced brine, as

well as the surface area above that delineated region.

25Rationale: There should not be a blanket prohibition concerning injection above USDW’s or at specific depths. This requirement is not necessary for the protection of USDWs and would remove a vast number of viable formations from consideration. Industry has shown that it can operate CO2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW below the injection zone. Moreover, unde r the proposed rule, there are other measures that would provide real assura nce of formation integrity and require operators to demonstrate that their proj ect will not endanger USDWs, making the lowermost USDW restriction unnecessary.

Individual 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. However, EPA disagrees with the suggested change. For additional informati on, please see the final rule at §146.95 and the preamble, as well as EPA's responses to comments on the Notice of Da ta Availability and Request for Comment.

Letter ID: 0170 Comment ID: 24146 Letter Lines: 488 to 497

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment: Rule Provision: 146.81(d) [Definition - Injection zone]

API Comments: Injection zone means a geol ogic formation, group of formations, or part of a formation that is of suffi cient areal extent, thickness, porosity, and permea bility to receive carbon dioxide RECEIVING FLUIDS through a well

or wells associated with a geologic sequestration project

Rationale: Existing definition in the CFR is sufficient and does not need to be changed. Furthermore, adding the sufficien cy requirement is not a definitional

issue and should be dealt with elsewhere.

Individual Response: EPA disagrees with the suggested edit . The final definition of injection zone at §146.81(d) remains unchanged, and reads as follows: “[A] geologic formation, group of formations, or part of a formation that is of sufficient areal extent, thickness, porosity, and permeability to receive carbon dioxide through a well or wells associated with a geologic sequestration project.”

Based on its evaluation of all public comments and input on the proposed rule and the NODA and Request for Comment, EPA has made many revisions to the Cla ss VI GS rule. Please see the final rule and preamble for additional information.

26Letter ID: 0170 Comment ID: 24147 Letter Lines: 499 to 507

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93)

Comment: Rule Provision: 146.81(d) [Definition - Post-injection site care]

API Comments: Post-injection site care means appropriate monitoring and other actions (including corrective action) needed following cessation of injection to assure that USDWs are not endangered , AS REQUIRED UNDER §146.93.

Rationale: Deleted "appropriate" because the definition of it is not clear. Deleted USDW phrase because it is incorporated in 146 requirements.

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and preamble for further discussi on on EPA's final approach. EPA adds that the owner or operator must monitor as specified in the post-injection site car e and site closure plan for at least 50 years or for the duration of th e alternative timeframe approved by the Director pursuant to requirements in §146.93(c), unless the ow ner or operator can make a demonstration earlier that the geologic sequestra tion project no longer poses a risk of endangerment to USDWs.

Letter ID: 0170 Comment ID: 24148 Letter Lines: 509 to 518

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment: Rule Provision: 146.81(d) [Definition - Pressure front]

API Comments: Pressure front means the zone of elevated pressure that is created by the injection of the carbon dioxide STREAM into the subsurface, For the purposes of this subpart, the pressure fr ont of a carbon dioxide plume refers to

a zone where there is a pressure differentia l sufficient to cause movement of injected fluids THE CARBON DIOXIDE STREAM or formation fluids FROM THE

INJECTION ZONE into a USDW.

Rationale: Clarification.

Individual Response: EPA disagrees with the suggested edit . The final definition of pressure front at §146.81(d) remains unchanged, and reads as follows: “[T]he zone of elevated pressure that is created by the injection of carbon dioxide into the subsurface. For the purposes of this subpart, the pressure front of a carbon dioxide plume refers to a zone where there is a pressure

differential sufficient to cause the movement of injected fluids or fo rmation fluids into a

USDW.”

Based on its evaluation of all public comments and input on the proposed rule and the NODA

27and Request for Comment, EPA has made many revisions to the Cla ss VI GS rule. Please see the final rule and preamble for additional information.

Letter ID: 0170 Comment ID: 24149 Letter Lines: 520 to 526

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93)

Comment: Rule Provision: 146.81(d) [Definition - Site closure]

API Comments: Site closure MEANS the poin t/time, as determined by the Director following the requirements under §146.93, at wh ich the owner or operator of a GS

site PROJECT is released from post-inj ection site care responsibilities.

Rationale: "GS project" is consistent with other definitions.

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and preamble for furthe r discussion on EPA's final approach.

Letter ID: 0170 Comment ID: 24150 Letter Lines: 528 to 537

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83)

Comment: Rule Provision: 146.81(d) [Definition - Transmissive fault or fracture]

API Comments: Transmissive fault or fract ure means a fault or fracture that has sufficient permeability and vertical extent to allow fluids to move between

formations BEYOND THE CONFINING ZONE.

Rationale: The term "between formations " is inaccurate since there can be multiple formations within a injection zone. The critical factor for transmissivity is movement of injected or displaced fluids beyond the confining

zone.

Individual Response: EPA acknowledges the comment but is retaining the requirement in the final rule as originally proposed under §146.81(d). EPA has retained the definition in the final rule, which is the same as the existing defin ition at §148.2, to address tr ansmissive faults and fractures that extend beyond the confining zone.

Letter ID: 0170 Comment ID: 24151 Letter Lines: 539 to 558

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

28Comment Code: 3130 2.1.3 Comments that operators s hould submit more (or different) geologic data than proposed

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking comment)

Comment: Rule Provision: 146.82(b)

API Comments: (b) A surface map showing the PROPOSED LOCATIONS FOR the injection well(s) for which a permit is sought and th e applicable area of review. Within the area of review, the map must show the number, or name a nd location of all KNOWN injection wells, pr oducing wells, abandoned wells , plugged wells or dry holes, deep STRATAGRAPHIC boreholes, Stat e or EPA approved subsurface cleanup sites, surface bodies of water, spri ngs, mines (surface and subsurface), quarries, water wells and other pertinent surface features including structures intended for human occupancy and roads. The map should also show faults, if known or suspected. Only information of public record is required to be included on this map;

Rationale: Faults are not shown on maps unless there is a surface expression of the fault. Also, faults are detailed in (d) below and this language appears

redundant.

The word "known" needs to be added to re move any implication that an applicant

has to conduct studies to de termine the location of wells that are not currently

documented in some fashion.

Individual Response: EPA did not delete “faults” from §146.82(b) because faults may have surface expressions that should be presented on submitted maps to complement the required cross section data. EPA is developing guidance on site characterization for GS projects to assist owners or operators and Directors in evalua ting permit requirements and applications under §146.82. The guidance provides recommendations rega rding characterizing the regional geology and hydrogeology of a proposed GS site as we ll as performing the n ecessary geochemical, geomechanical, and geophysical analyses of the injection and confining zone. The guidance can

be found on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

Please see the final rule and the discussion of geologic site charact erization in the preamble for

additional information.

EPA acknowledges that some smaller fractures may not be detectable during the site characterization process, and cl arifies that §146.82(a)(3 )(ii) requires the ow ner or operator to submit data on known or suspected faults and fractures (i.e., not al l fractures). Other requirements for GS injection wells and sites can mitigate the potential impacts of unidentified fractures. These include limitations on injec tion pressures to avoid propagation of existing fractures in the confining zone (§146.88(a)), co llection and assessments of CO2 monitoring data at the site, and AoR reevaluations (§146.84(e)) to assess possible CO2 movement through high29permeability regions (i.e., faults and/or fractures) not detected in the initial site characterization.

EPA believes that a determination about whether or what information may be necessary (for a specific GS project) is outside of the public record and will be site-specific and based on knowledge of the site, data availability, and data quality. For inst ance, in meeting the requirement to tabulate information on wells in the AoR, the Director has the discretion to require the owner or operator to supplement a data records search if ther e is reason to believe that the incompleteness of available informa tion could compromise USDW protection from endangerment.

Letter ID: 0170 Comment ID: 24152 Letter Lines: 560 to 568

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

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83)

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking comment)

Comment: Rule Provision: 146.82(c)

API Comments: (c) A MAP DELINEAT ING the area of review based on UPON modeling, using ALL AVAILABLE data INCL UDING DATA obtained dur ing logging and testing of the well and the formation as requir ed by paragraphs (l), (r), and (s) of this section ANY WELLS IN THE AREA OF REVIEW

Rationale: This appears to be related to a condition where a well is already drilled. This does not align with reques ting information to receive a permit.

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)).

The requirement to provide the final area of review based on m odeling and data obtained during logging and testing is in the fina l GS rule at §146.82(c)(1). Plea se see the final rule and the discussion of geologic site characterization in the preamble for additional information.

Letter ID: 0170 Comment ID: 24153 Letter Lines: 570 to 624

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

Comment Code: 3130 2.1.3 Comments that operators s hould submit more (or different) geologic data than proposed

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking

30comment)

Comment: Rule Provision: 146.82(d)(1) and (2)

API Comments: (d) KNOWN informati on on the geologic structure and hydrogeologic RESERVOIR properties of the proposed storage site and overlying formations, including:

(1) ISOPACH maps and OF THE PROPOSED INJECTION AND CONFINING ZONE(S), A STRUCTURAL CONTOUR MAP HUNG ON THE TOP OF THE PROPOSED

INJECTION ZONE, AND AT LEAST TWO GEOLOGIC cross s ections of the area of review SHOWING

THE

GEOLOGIC FORMATIONS FROM THE SURFACE TO TOTAL DEPTH.

(2) Location, orientation, and pr operties of known or suspected

SUBSURFACE faults and fractures that may transect the confining zone(s) in

the area of review and a determination that they would not interfere with containment;

Rationale: If the information is not k nown, it cannot be repo rted. "Reservoir" and changes to (1) and (2) are technical corrections.

Fractures generally can’t be identified until a well is drilled and evaluated. Even then, only fractures in the immediate vicinity of the wellbore

can be identified.

This responsibility is best left with EPA.

Rule Provision: 146.82(d)(3)

API Comments: (3) Information on seismi c history THAT HAVE AFFECTED THE

PROPOSED AREA OF REVIEW, INCLUDING KNOWLEDGE OF PREVIOUS SEISMIC EVENTS, including the presence and depth of seismic sources a nd a determination that the seismicity

w ould not interfere with containment;

Rationale: Information on seismic history should have some degree of relevance to the project. This responsibil ity is best left with EPA.

Rule Provision: 146.82(d)(4)

API Comments: (4) Data on the depth, ar eal extent, thickne ss, mineralogy, porosity, permeability and capillary RESERVOIR pressure of the injection and confining zone(s) WITHIN THE AREA OF REVIEW; includi ng geologic/facies

31changes based on field data which may include geologic cores, outcrop data, seismic surveys, well logs, and name s and lithologic descriptions;

Rationale: Deleted capillary pressure becau se it is too hard to measure outside of the lab. Using sidewall cores, it ma y be difficult to determine capillary pressure. Additionally, full cores are not available until after the well being permitted is drilled.

Rule Provision: 146.82(d)(5)

API Comments: (5) KNOWN geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid pressures within the confining zone(s) WITHIN THE AREA OF REVIEW; and

Rationale not provided

Individual Response: EPA acknowledges that some smaller fractures may not be detectable during the site characterization pr ocess, and clarifies that §146.82( a)(3)(ii) require s the owner or operator to submit data on known or suspected fau lts and fractures (i.e., no t all fractures). Other requirements for GS injection wells and sites can mitigate the potential impacts of unidentified fractures. These include limitations on injec tion pressures to avoid propagation of existing fractures in the confining zone (§146.88(a)), co llection and assessments of CO2 monitoring data at the site, and AoR reevaluations (§146.84(e)) to assess possible CO2 movement through highpermeability regions (i.e., faults and/or fractures) not detected in the initial site characterization. Regarding the requirement to determine capillary pressure, EPA recognizes that this information may not be available until after a well has been drilled. EPA revised §146.82 so that the final regulation specifies separate requirements for information to be submitted with the permit application and before well construction is approved (at §146.82(a)) and information to be submitted before operation of the well is auth orized (at §146.82(c)). Final information on injection zone pressures woul d be required following drilling of the well, at §146.82(c)(4).

EPA disagrees that information submitted with Cl ass VI permit applications should be limited to known (i.e., previously available) data. Site-specific conditions ma y affect the suitability of a proposed site. Therefore the owner or operator must provide to the Director the necessary preliminary information to support a permit decision.

Letter ID: 0170 Comment ID: 24154 Letter Lines: 626 to 659

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

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83)

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking comment)

Comment: Rule Provision: 146.82(e)

API Comments: (e) A tabulation RECORD of all wells ARTIFICIAL

32PENETRATIONS within the area of review which penetrate THAT REACH the injection or confining zone(s). Such data AS AVAILABLE IN THE PUBLIC RECORD must include a description of each well’s PENETRATION’S type, construction, date drilled, location, depth, reco rd of plugging and/ or completion, and any

additional information the Director may require;

Rationale: Artificial penetrations is a more inclusive term.

Rule Provision: 146.82(f)

API Comments: (f) Maps and stratigraphic cross secti ons indicating the general

vertical and lateral limits of all USDW s, water wells and springs within the area of review, thei r positions relative to the injection zone(s) and the direction of water movement, where known; POTENTIOMETRIC (WATER LEVEL)

SURFACE MAP(S) OF EXISTING AQUIFERS BEING UTIL IZED AS PRIVATE OR PUBLIC WATER

SUPPLIES

AND THE DIRECTION OF GRO UNDWATER FLOW IN THESE AQUIFERS WITHIN THE

AREA OF

REVIEW. AT LEAST TWO GEOLOGIC CRO SS SECTIONS SHOWING THE THICKNESS

AND GENERAL

VERTICAL AND LATERAL LIMITS OF ALL US DWS WITHIN THE AREA OF REVIEW.

No rationale provided

Rule Provision: 146.82(g)

API Comments: (g) B aseline geochemical data on subsurface formations, including all USDWs in the area of review COMPILATION OF AVAILABLE

GEOCHEMICAL

DATA ON THE PROPOSED INJECTION ZONE AND NEAREST POROUS AND

PERMEABLE FORMATION

ABOVE THE CONFINING ZONE.

Rationale: Limits the data to be submitted to available information and to the injection zone and the zone immediately above the confining zone which are the zones most likely to be monito red for potential CO2 leakage.

Individual Response: As described above, EPA disagrees that the information that is submitted to support a Class VI permit application s hould be limited to known/available data.

EPA believes that a thorough unde rstanding of the hydrogeologic c onditions of all USDWs in the AoR is necessary, and disagrees with the su ggested edits because the GS rule, as written, affords flexibility to owners or operators and Di rectors to tailor the site characterization process to the unique features of the site. EPA enc ourages owners or opera tors and Directors to collaborate and consult during site characterization to discuss info rmation needs and ensure that

33all appropriate data to assess the suitability of the site are collected. The Director has the authority to request additional hydrogeologi c data or other data on USDWs as well.

The Agency believes that the requirement at §146.82(a)(6) to submit baseline geochemical data on subsurface geologic formations, including a ll USDWs in the AoR, is appropriate and protective of USDWs. EPA believe s that this data will support monitoring plan development, inform injectate fate and transport model de velopment (e.g., by providing appropriate input parameters), and provide information needed to respond to any unexpected and unpermitted leaks outside of the injection zone. The baseli ne geochemical information will allow the owner or operator and permitting authority to evaluate monitoring data and identify any changes in subsurface geochemistry that may indicate fluid movement.

The rule requires geochemical analysis of, at a minimum, the injection zone, confining zone, and all USDWs (§146.82(a)(6)). These geochemical tests ar e necessary to ensure the adequacy of the confining system and to serve as a baseline for future monitoring. The Director has the discretion to require geochemical analysis of additional s ubsurface zones if, in the Director's opinion, they are necessary for the protection of USDWs from endangerment.

Letter ID: 0170 Comment ID: 24155 Letter Lines: 661 to 690

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: Rule Provision: 146.82(h)

API Comments: (h) Proposed operating da ta: (1) Average and maximum daily

INJECTION rate and volume of the carbon di oxide stream; (2) Av erage and maximum SURFACE injection pressure;

Rationale: Technical clarifications.

Rule Provision: 146.82(k)

API Comments: (k) Proposed stimulati on program and a determination that stimulation will not interfere with containment;

Rationale: This responsibility is best left with EPA.

Rule Provision: 146.82(n)

API Comments: (n) A WELLBORE schematic or other appropriate drawings of t he

surface and of the subsurface constr uction details of the well AND SURFACE

WELLHEAD CONSTRUCTION.

34Rationale: Technica l clarification.

Rule Provision: 146.82(q)

API Comments: q) The ANY status of corrective acti on on wells in the area of review;

Rationale: Clarifies that wells not needing corrective action will not have a

corrective action status.

Individual Response: EPA acknowledges the commenter’s suppor t for parts of the requirements under 146.82. EPA disagrees with suggested tec hnical clarifications regarding proposed operating data, needs for the stimulation program, and the status of corrective action. EPA adds that it is developing guidance for owners or operators on the geol ogic site characterization, AoR, and corrective action processes. These guidances will provide recommendations and clarify the intent of all required elements of a permit application. The guidances can be found on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_se questration.cfm.

Letter ID: 0170 Comment ID: 24156 Letter Lines: 692 to 704

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

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

Comment: Rule Provision: 146.83(a)(2)

API Comments: (2) A confini ng zone(s) that is LATERALLY CONTINUOUS AN D free of KNOWN TRANSECTING, transmissive faults or fractures and of sufficient areal extent and integrity to contain the inj ected carbon dioxide stream and displaced

formatio n fluids and allow injection at pr oposed maximum pressures and volumes without initiating or prop agating fractures in the confining zone(s); and OVER

AN AREA SUFFICIENT TO PR EVENT THE MOVEMENT OF INJECTED OR DISPLACED

FLUIDS INTO A USDW;

Rationale: The proposed clarification k eeps the emphasis on the non-endangerment of USDWs and limits the requirements to th at which is known or can be readily

determined.

Individual Response: The Agency believes that the re quirement at §146.83(a)(2) that the confining zone be free of transmissive faults or fractures as written is appropriate for Class VI wells and is necessary to ensure containment of the injectate, and that requiring the confining

zone to be free of transmissive faults maxi mizes protection of USDWs from endangerment. Class I hazardous waste injection well operators must also meet a similar requirement that the site is free of transmissive faults or fractures; they have successfully made such demonstrations

35in the past. EPA adds that the Director must ev aluate all geologic data on the site to ensure protection of USDWs from endangerment befo re approving a site fo r a GS project.

Letter ID: 0170 Comment ID: 24157 Letter Lines: 706 to 715

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

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones (seeking comment)

Comment: Rule Provision: 146.83(b)

API Comments: (b) At the Direct or‘s discretion, owners or o perators of Class VI wells must identify and characterize additional zones that will impede vertical fluid movement, are free of fa ults and fractures that may interfere with containment, allow for pressu re dissipation, and provide additional opportunit ies for monitoring, mitigation and remediation.

Rationale: This paragraph creates a presum ption that additional confining zones WILL be required. It is also redundan t given the previous sections.

Individual Response: EPA clarifies that secondary confini ng zones are not required for all GS sites. Rather, secondary confini ng zones are required when the Di rector determines that these zones are needed to maximize the protection of USDWs from endangerment. EPA retains the requirement to identify additional containment/confining zones, if required by the Director, as proposed (e.g., §146.83(b)). EPA believes that, in some situations, the presence of additional confining and containment zones above the pr imary (i.e., lowermost) confining zone can improve USDW protection. These layers could fu rther impede vertical fluid movement and allow for pressure dissipation, and also provide additional sites for monitoring, mitigation, and remediation. The Agency believes that providing the Director discretion will allow consideration of a range of sites for GS, based on site-speci fic conditions, and ensure USDW protection. EPA believes that requiring appropriate site charac terization by the owner or operator (under §146.82) and providing an appropriate degree of flexibility to the Director to evaluate site-specific geologic data will afford the greatest protection of USDWs from endangerment.

Letter ID: 0170 Comment ID: 24158 Letter Lines: 717 to 728

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

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling CO2 movement

Comment: Rule Provision: 146.84(a)

API Comments: (a) The area of review is the region surrounding the geologic sequestration project that may be im pacted by the injection activity. The area of review is based on com putational modeling that acc ounts for the physical and chemical properties of all phases of the injected carbon dioxide stream. THE

36SUBSURFACE THREE-DIMENSIONAL EXTE NT OF THE CARBON DIOXIDE PLUME,

ASSOCIATED PRESSURE FRONT, AS WELL AS THE OVERLYING FORMATIONS AND SURFACE

AREA ABOVE THAT

DELINEATED REGION.

Rationale: Edits make this provision consis tent with the definition of "Area of Review", which was revised.

Individual Response: EPA disagrees that the AoR definition needs to specifically include the overlying formations and surface area above the delineated region. The intent of the AoR, a long-standing concept within the UIC Program, is to delineate the surface area and all subsurface formations below it that may potentially be impacted by injection activity. Acceptable delineation models will provide predictions of CO 2 fate and transport, as well as changes in formation pressure, in three dime nsions as a function of time that can be used to delineate the subsurface storage site and the AoR. Although EP A disagrees with the commenter's suggested change, the Agency has carefully considered all comments on the AoR definition at 146.84(a) and modified it to read as follows: The regi on surrounding the geologic sequestration project where USDWs may be endangered by the injection activity. The ar ea of review is delineated using computational modeling that accounts for the physical and chemical properties of all phases of the injected CO2 stream and is base d on available site characterization, monitoring, and operational data. EPA believes that this defi nition is sufficiently broad and describes both the intent of the computational modeling and the relationship of th e AoR to areas that are subject

to the risks associat ed with injection.

Letter ID: 0170 Comment ID: 24159 Letter Lines: 730 to 741

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

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action plan

Comment: Rule Provision: 146.84(b)

API Comments: (b) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan to delin eate the area of review for a proposed geologic sequestration project, periodically reevaluate the delineation, and perform corrective action that meets th e requirements of this section and is IN A MANNER AND AT A FREQUENCY acceptable to the Director. As a part of the permit application, for approval by the Director the owner or operator must

submit an area of review and corrective act ion plan that includes the following

information:

Rationale: Clarification.

Individual Response: EPA disagrees with the suggested cha nge, and is retaining the approach of setting a minimum fixed frequency for reeval uating the AoR but has, based on commenters'

37input, changed the frequency from ten years to at least every five ye ars, as specified in §146.84(e). EPA agrees with commenters that site-specific informati on is an important factor in determining an appropriate AoR reevaluation freq uency, and adds that th e owner or operator's AoR and corrective action plan must describe th e minimum fixed frequency for reevaluating the AoR and the site-specific condi tions on which this frequency is based. EPA adds that the

Director will evaluate the proposed plan in connection wi th a review of a vast amount of geologic and proposed operating da ta in determining whether to approve the plan. EPA is developing guidance describing reco mmended approaches to prepar ing all of the required GS project plans, which will addres s considerations for determining an appropriate AoR reevaluation schedule. The guidance will be available on EPA's web site at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 24160 Letter Lines: 743 to 768

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

Comment Code: 3500 2.2.3 Area of Review Reevaluation (seeking comment)

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action plan

Comment: Rule Provision: 146.84(b)(2)

API Comments: (2) A description of: (i) The minimum fixed frequency, not to ex ceed 10 years, the owner or operator proposes to reevaluate the area of review; (ii) The monitoring and operat ional conditions that would warrant a
reevaluation of the area of review prior to the next scheduled reevaluation as determined by the minimum fixed frequency established in paragraph (b)(2)(i) of

this section. (iii) (I) How monitoring and operational data (e.g., injection rate and pressure) will be used to inform an area of review reevaluation; and

No rationale provided

Rule Provision: 146.84(b)(2)

API Comments: (iv II) How corrective action will be conducted to meet the requirements of paragraph (d) of this section, including what corrective action will be performed prior to injection and what, if any, portions of the area of

review will have corrective action ad dressed on a phased basis and how the phasing will be determined; how corrective action will be adjusted if there are changes in the area of review; and how site access will be guaranteed

ARRANGED for future corrective action.

Rationale: Future access cannot be guarant eed for an area in advance that may

not even be within the bounda ries of the AOR/ project.

38Individual Response: EPA disagrees with the suggested cha nges. Regarding reevaluation of the AoR, EPA believes that periodic AoR reevaluation at a set frequency of at least every five years is necessary to ensure protection of USDWs fr om endangerment and address the uncertainties inherent in predictive modeling. Periodic Ao R reevaluations at §146.84( e) ensure that a deliberate effort is made to verify, based on m onitoring and operational da ta, that the CO2 plume is moving within the subsurface as predicted. EP A believes that less frequent reevaluations may not be sufficient to appropriately model plume a nd pressure front moveme nt, establish conditions for corrective action, and ensure prot ection of USDWs from endangerment.

EPA clarifies that if site m onitoring data agrees with the existing AoR delin eation, a model recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration

that the current AoR delineation is ad equate based on site monitoring data.

To the comment on site access, EPA clarifies that the purpose of the corrective action requirement at §146.84(d) is to ensu re that all wells in the AoR th at have the potential to cause

the movement of CO2 or other fluids into or between USDWs receive appropriate corrective action. In general, to meet this requirement, the owner or operato r will most likely need to obtain the right of access to wells that may require co rrective action, and demonstrate they have done this in their proposed AoR and corrective action pl an. The final rule reta ins the requirement as proposed.

Letter ID: 0170 Comment ID: 24161 Letter Lines: 770 to 793

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

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling CO2 movement

Comment: Rule Provision: 146.84(c)(1)

API Comments: (1) Predict, using computationa l modeling, the projected lateral and vertical migration of the carbon dioxi de plume and formati on fluids in the

subsurface from the commencement of injection activities until the plume movement ceases, pressure differentials sufficient to cause the movement of injected fluids or formation fluids in to a USDW are no longer present, or

after FOR a fixed time period as determined by the Director. The model

MODELING must:

Rationale: Clarification.

Rule Provision: 146.84(c)(1)

API Comments: (i) Be based on detailed geologic data collected AVAILABLE to characterize the injection zone, conf ining zone and any additional zones ; and anticipated operating data, including injection pressures, rates and total volumes over the proposed life of th e geological sequest ration project THE DURATION OF INJECTION; ( ii) Take into account any RELEVANT geologic

39heterogeneities, AND data quality, a nd their possible impact on model predictions; and

Rationale: Allows the use of all available data, not just data collected specifically for this permit.

Individual Response: EPA has clarified the language in §146.84(c)(1) for the final rule. It now reads, “Predict, using existing site characte rization, monitoring a nd operational data, and computational modeling, the projected lateral and vertical migration of the carbon dioxide plume and formation fluids in the subsurface from the commencement of injection activities until the plume movement ceases, until pressure differentials sufficient to cause the movement of injected

fluids or formation fluids into a USDW are no longer present, or until the end of a fixed time period as determined by the Director.”

The final rule retains §146.84(c)(1)(ii) as propos ed, except that it now requires owners or operators to take into account ot her discontinuities in addition to geologic heterogeneities when determining the AoR.

EPA disagrees that only the injection and conf ining zones should be included in AoR modeling of GS sites. EPA believes that the modeling shou ld also take into acc ount the possibility of displaced fluids or brines caused by a lateral and/ or vertical pressure plume, and therefore it may be necessary to include additional zones along with the confining/injection zones to ensure the integrity of the confining zone and ultim ately protect a USDW from endangerment.

Letter ID: 0170 Comment ID: 24162 Letter Lines: 795 to 805

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

Comment Code: 3420 2.2.2.1 Scope of the inventory pr ocess (e.g., reliance on publicly available information, depth of wells)

Comment: Rule Provision: 146.84(c)(2)

API Comments: (2) Using met hods approved by the Director, Identify all KNOWN ARTIFICIAL penetrations INTO THE CO NFINING ZONE AVAILABLE IN THE PUBLIC RECORD, including active and aba ndoned wells and underground mines, in the area of review that may penetrate REACH the confining zone. Provide a description of each well‘s type, construction, date drilled, location, depth, record of plugging and/or completion, and any additi onal information the Director may require; and

Rationale: Changed for consis tency with earlier language.

Individual Response: EPA is retaining this requiremen t as proposed. EPA agrees with commenters that, for most GS sites, relying on da tabase and other public records searches (i.e.,

40of "known" artificial penetrati ons) will be sufficient to meet the requirements at §146.84(c)(2). However, the Agency recognizes that there ma y be situations where additional surveys or research to locate wells may be appropriate. For example, there may be cases where the Director may determine that ground or airborne surveys for wells are appropriate, e.g., if there is reason to believe, based on knowledge of the site or of available data, that the incompleteness of information on known wells could compromise US DW protection from endangerment. In order to preserve the Director's disc retion to require an operator to supplement a records search, EPA did not make the suggested change.

EPA clarifies that any well that penetrates the co nfining zone, even if it does not extend all the way through the confining formation, is to be included in the tabulation. The guidance describes EPA's recommended approaches for the data to be considered in an initial AoR delineation, how to apply computational m odeling to delineate the AoR, perfor ming corrective action at GS sites, and, when appropriate, completing AoR reevalua tions. 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: 0170 Comment ID: 24163 Letter Lines: 807 to 814

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

Comment Code: 3400 2.2.2 Corrective Action

Comment: Rule Provision: 146.84(c)(3)

API Comments: (3) Determine which aba ndoned wells IDENTIFIED IN 146.84 (C) (2)

in the area of review have been plugged (as required by §146.92) in a manner that prevents the movement of carbon dioxide or associated FORMATION fluids that may endanger USDWs.

Rationale: Remove as redundant.

Individual Response: EPA clarifies that the term "asso ciated fluids" as proposed in §146.84(c)(3) refers to formation fluids, other in jectates, etc. that may be present in the

subsurface and affect movement of the CO2 plume and/or pre ssure front. EPA believes this terminology would incorporate any fluids in the subsurface that could potentially move through artificial penetrations and affect USDWs. EPA has revise d the language at §146.84(c)(3) to read,

"... carbon dioxide or other fluids that may endanger USDWs..." EP A disagrees that deleting the term area of review is necessary and has reta ined the term in the final rule language.

Letter ID: 0170 Comment ID: 24164 Letter Lines: 816 to 827

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

Comment Code: 3460 2.2.2.3 Acceptable corrective action techniques for GS sites (e.g., cements)

41Comment: Rule Provision: 146.84(d)

API Comments: (d) Owners or operators of Class VI wells must perform corrective

action USING MATERIALS SUITABLE FO R USE WITH THE CARBON DIOXIDE

STREAM AND FORMATION FLUIDS, on all wells in the area of review IDENTIFIED IN 146.84(C) (2) that are determined to need correc tive action". using methods necessary to prevent the movement of fluid into or between USDWs including use of corrosion resistant materials, where appropriate.

Rationale: Experience with CO2 based EO R strongly supports the use of many conventional materials that might not meet the technical definition of

"corrosion resistant".

Individual Response: EPA revised the text at §146.84(d) to re quire the use of materials that are "compatible with the carbon dioxide stream." EPA believes this language change addresses

commenters' concerns and is also consiste nt with other language regarding materials requirements in the GS rule.

Letter ID: 0170 Comment ID: 24165 Letter Lines: 829 to 837

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

Comment Code: 3400 2.2.2 Corrective Action

Comment: Rule Provision: 146.84(e)

API Comments: (e) If monitoring data in dicate an endangerment to USDWs, the owner or operator must notify the Direct or and cease operations as required by §

146.94.

Rationale: This is not needed since § 146.94 already specifies the notification and cessation of injection. API suggests the removal of this language as unnecessarily duplicative.

Individual Response: Based on consideration of all public comments and other information, EPA deleted this provision from §146.84. The fina l rule now contains a provision in §146.91(c) that requires the owner or opera tor to report within 24 hours any evidence that the carbon dioxide stream or associated pressure front may cause an endangerment to a USDW. EPA believes this change consolidates reporting requirements in one place and provides additional clarity.

Letter ID: 0170 Comment ID: 24166 Letter Lines: 839 to 847

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

Comment Code: 3530 2.2.3.1 AoR reevaluation fre quency (seeking comment)

42Comment: Rule Provision: 146.84(f)

API Comments: (f) At the minimum fixed frequency, not to exceed 10 years, as specified in the approved area of review and corrective acti on plan, or W hen monitoring and operational conditions warrant, owners or operators must:

Rationale: Rather than a fixed time period, API recommends following a performance based approach that would be based on significant changes in injection parameters or an omalous monitoring results.

Individual Response: EPA believes that periodic AoR r eevaluation at a set frequency is necessary to ensure protecti on of USDWs from endangerment and address the uncertainties inherent in predictive modeling. Periodic Ao R reevaluations at §146.84( e) ensure that a deliberate effort is made to verify, based on m onitoring and operational da ta, that the CO2 plume is moving within the subsurface as predicted. EP A believes that less frequent reevaluations may not be sufficient to appropriately model plume a nd pressure front moveme nt, establish conditions for corrective action, and ensure prot ection of USDWs from endangerment.

EPA clarifies that if site m onitoring data agrees with the existing AoR delin eation, a model recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration

that the current AoR delineation is ad equate based on site monitoring data.

Based on the comments received (including those by water associati ons, an energy company, associations, industries, states, and envir onmental groups), EPA has changed the minimum frequency for the AoR reevaluation from ten years to at least every five year s. EPA believes that this revised frequency addresse s commenters' concerns about th e inherent uncertainties in modeling CO2 movement, the emerging nature of GS technology, risk-b ased targeting of monitoring activities, and the unique nature of CO2 GS.

Letter ID: 0170 Comment ID: 24167 Letter Lines: 849 to 855

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

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action plan

Comment: Rule Provision: 146.84(f)(4)

API Comments: (4) Submit an amended area of review and corrective action plan or demonstrate to the Director through monito ring data and modeling results that no

amendment CHANGE to the area of review and corrective action plan is needed.

Rationale: Clarification

Individual Response: EPA disagrees with the suggested changes and believes the proposed text

43is clear as written. For additional information on EPA's approach to AoR and corrective action, please see the final rule and preamble.

Letter ID: 0170 Comment ID: 24168 Letter Lines: 857 to 884

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

Comment Code: 5430 2.9.1 Comments on proposed financia l responsibility requirements (40 CFR 146.85)

Comment: Rule Provision: 146.85(a)(1)

API Comments: (1) The Direct or receives WELL PLUGGING REPORT IDENTIFIED IN 146.92(D) and approves OR COMPLETION OF the completed post-injection site care and site closure pl an AS APPROPRIATE; and

Rationale: Maintenance of the well pl ugging financial obligation until site closure is not necessary. The Director s hould have the authority to release the obligation once the well is plugged.

Rule Provision: 146.85(b)

API Comments: (b) The owner or operator must provide to the Director, at a frequency determined by the Director, BU T NO MORE THAN ANNUALLY, written updates of adjustments to the cost esti mate to account for any amendments CHANGE to

the area of review and co rrective action plan (§146.84) , the injection well plugging plan (§146.92), and the post-injecti on site care and site closure plan (§146.93).

Rationale: Updates more frequent than annual is not justified.

Rule Provision: 146.85(c)

API Comments: (c) The owner or operator must notify th e Director of adverse financial conditions such as bankruptcy, that may affect the ability to carry out injection well plugging and post-inje ction site care and site closure.

Rationale: Clarification.

Individual Response: Owners or operators have the flexib ility to choose from a variety of

financial instruments to meet their financial re sponsibility obligations. For example, owners or operators may use one or multiple financial responsibility instruments for well plugging and PISC (§146.85(a)(6)). However EPA will not allo w for a separate financial responsibility demonstration for well plugging and PISC (i.e., a demonstration submitted prior to well plugging and the beginning of the post-injec tion site care period rather than with the permit application). A demonstration of financial responsibility for all ph ases of the GS project will be required prior to

the issuance of a Class VI permit (§146.85(a)(5)(i)).

44To ensure that financial resources are availabl e to protect USDWs from endangerment, the GS rule (at §146.85) identifies qualifying financial inst ruments, the time frames over which financial responsibility must be maintain ed, procedures for estimating the costs of activities covered by the financial instruments, procedures for notifyi ng the Director of adve rse financial conditions, and requirements for adjusting cost estimates to reflect changes to the project plans.

In addition, on an annual basis, the owner or opera tor must adjust the cost estimate for inflation,

increase or decrease the value of the financial instrument to matc h the cost estimate, and provide any updated information related to their financial respons ibility instrument(s), or at any other time deemed appropriate by the Director. Th ese annual reviews provide a mechanism for revising cost estimates up or down to account fo r changes in the projec t, including the execution of environmental obligations as phase s of a GS project are completed.

Regarding the suggested edit at §146.85(a)(1), EPA clarifies that the fina ncial instrument the owner or operator provided to meet the requ irements under §146.85 will be released when the phase of the project for which the instrument was required is complete and all financial obligations for that instrument have b een met, pursuant to §146.85(b)(2) and §146.93.

The GS rule, at §146.85(c), requires the owner or ope rator to have a detailed written estimate, in current dollars, of the cost of: performing co rrective action on wells in the AoR, plugging the injection well(s), PISC and site closure, and emergency and remedial response. A cost estimate must be prepared separately for each of these ac tivities and be based on th e costs to the owner or operator of hiring a third party (who is neither a parent nor a subsid iary of the owner or operator) to perform the activities. However, EPA is not requiring independent th ird-party reviews of owner or operator cost estimates.

EPA is developing guidance on fina ncial responsibility for GS we lls. The guidance will include a

discussion on how best to estimate costs to assist Class VI well owners or operators, third party insurers or providers of financial instruments, and permitting authorities in developing estimates

of the costs associated with va rious GS activities. The guidance is available on EPA's website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

EPA did not make the proposed edits at §146.85(b) a nd (c), but did extensiv ely revise and clarify the financial responsibility requirements. See the final GS rule and preamble for additional information on EPA's final approach.

Letter ID: 0170 Comment ID: 24169 Letter Lines: 886 to 894

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

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking comment)

Comment: Rule Provision: 146.85(d)

API Comments: (d) The operato r must provide an adjustment of the cost estimate

45to the Director if the Director has reason to believe that original THE MOST RECENT demonstration is no longer adequate to cover the cost of injection well plugging (as required by §146.92) an d post-injection site ca re and site closure (as required by §146.93)

Rationale: Clarification.

Individual Response: EPA agrees that it is important to periodically update cost estimates that support financial responsibility determinations. EPA clarifies th at the GS rule, at §146.85(e), requires the owner or operator to provide annua l updates to the cost es timate to account for any amendments to the AoR and corrective action plan, the injection well plugging plan, and the PISC and site closure plan. See the final rule and preamble for further di scussion of EPA's final approach to financial responsibility.

Letter ID: 0170 Comment ID: 24170 Letter Lines: 896 to 905

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

Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 146.86)

Comment: Rule Provision: 146.86(a)(1)

API Comments: (1) Prevent the movement of fluid into or between USDWs or into any unauthorized zones; CONTAINING ANY CONTAMINANT INTO USDWS, IF THE

PRESENCE

OF THAT CONTAMINANT MAY CAUSE A VIOLATION OF ANY PRIMARY DRINKING

WATER

REGULATION UNDER 40 CFR PART 142 OR MAY OTHERWISE ADVERSELY AFFECT

THE HEALTH OF PERSONS.;

Rationale: The proposed changes reflect th e nonendangerment standard that is the basis of the UIC program.

Individual Response: EPA disagrees that the proposed la nguage provided in §146.86 does not reflect the non-endangerment standard as required under the SDWA. EPA believes that protection of USDWs from endangerment and prev ention of fluid movement between formations is paramount and the language as proposed m eets the non-endangerment standard, therefore it is not necessary to make such edits. Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs and maintain in tegrity of the well thro ughout the lifetime of a GS project. This is the foundation of the requ irements for construc tion and pre-operational testing of Class VI wells at §§146.86 and 146.87.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment EPA has made many revisions to the GS rule. Please see the final rule and preamble for additional information.

46Letter ID: 0170 Comment ID: 24171 Letter Lines: 907 to 923

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

Comment Code: 3860 2.3.3 Well component degradation

Comment: Rule Provision: 146.86(b)(1)

API Comments: (1) Casing and cement or othe r materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the operating life of the geologic sequestration project WELL. All well materials must be compatible SUITABLE FOR USE with the fluids with which the materials may be expected to come into contact and meet or exceed TEST standards OR PRACTICES developed for such materials by the American Petroleum Institute, ASTM International, or comparable sta ndards acceptable to the Director. The casing and cementing program must be designe d to prevent the movement of fluids

into or between USDWs. In order to allo w the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information:

Rationale: The life of a geologic sequestra tion project could be different than

the life of the well. Class VI well de sign should be based on the life of the

well.

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 th e 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 the post-injec tion site care period and beyond. While th e 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 cementing help ensure that the Class VI well will not serve as a conduit fo r movement of fluids

associated with future injection operations.

Letter ID: 0170 Comment ID: 24172 Letter Lines: 925 to 931

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

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)

Comment: Rule Provision: 146.86(b)(1)

API Comments: (v) Corrosiveness COMPOSITION of the car bon dioxide stream and formation fluids;

47Rationale: There is no method for measurement of "corrosiveness" of a CO2

stream. The relevant information is the composition of the CO2 stream.

Individual Response: EPA clarifies that, although corro siveness does not have a unit of measure, corrosiveness can be technically measured and described. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational

information that the Director needs to determine appropriate standards for the tubing and packer.

Letter ID: 0170 Comment ID: 24173 Letter Lines: 933 to 938

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

Comment Code: 3860 2.3.3 Well component degradation

Comment: Rule Provision: 146.86(b)(1)

API Comments: (vi) Down-hole te mperatures AND PRESSURES; (viii) Type or grade of cement AND ADDITIVES; and

Rationale: Technica l clarification.

Individual Response: EPA agrees with the suggestion that §146.86(b)(1)(viii) be revised to also address cement additives. In the final GS rule, the subparagraph reads as follows: "Type or grade

of cement and cement additives."

EPA clarifies that informati on on down-hole pressures is re quired at §146.86(b)(1)(ii).

Letter ID: 0170 Comment ID: 24174 Letter Lines: 940 to 946

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

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment)

Comment: Rule Provision: 146.86(b)(2)

API Comments: (2) Surface casing must exte nd through the base of the lowermost

USDW ABOVE THE INJECTION ZONE a nd be cemented to the surface.

Rationale: In some parts of the US the USDW is very deep and this standard may preclude geologic sequestra tion in these areas.

Individual Response: EPA disagrees with the suggested edit or that th e surface casing requirements in the GS rule preclude injecti on below deep USDWs. The final GS rule at §146.86(b)(2) requires that surface casing extend th rough the base of the lowermost USDW and be cemented to the surface through the use of single or multiple strings of casing and cement. It does not, however, specify how cementing must be accomplished, and gives flexibility to the

48owner or operator to propose alternate methods - to provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment. EPA notes that there are many potential ways to meet the requirement , such as the use of staged cementing.

EPA recognizes concerns regardi ng construction of Class VI wells where the lowermost USDW is very deep. To further address comments on d eep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells opera ting under injection depth waivers must comply with additional construction require ments to ensure that wells used to inject above or between USDWs are protective. See the discussion of the wa iver approach in the preamble to the final GS

rule for additional information.

Letter ID: 0170 Comment ID: 24175 Letter Lines: 948 to 975

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: Rule Provision: 146.86(b)(3)

API Comments: (3) At leas t one long string casing, using a sufficient number

of centralizers SET IN A MANNER SO AS TO CREATE A CEMENT BOND THROUGH

THE INJECTION AND CONFINING ZONE(S). THE L ONG STRING CASING must extend to the injection zone and must be cemented ISOLATED by circulating cement to the surface in one or more stages. PLACING CEMENT AND/OR OTHER ISOLATION

TECHNOLOGIES AS NECESSARY TO PR OVIDE ADEQUATE ISOLATION OF THE

INJECTION ZONE

AND PROVIDE FOR PROTECTION OF USDWS.

Rationale: Cementing to surface is not neces sary to protect USDWs, and may have negative consequences, as follows. Cement to surface would elim inate the ability to monitor pressures in this annulus a nd would limit flexibility of remedial options. As revised, the propos al would allow for application and development of alternative technologies. See API RP90 for description of risk-based approach for managing situations involving annular casing pressure. Industry experience with CO2 EOR under the Class II program demonstrates the effectiveness of existing cementing procedures.

Rule Provision: 146.86(b)(4)

API Comments: (4) Circulation of cem ent may be accomplished by staging. The Director may approve an alternative method of cementing in cases where the

cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the ceme nt does not allow fluid movement behind

the well bore.

49Rationale: Same as above

Individual Response: EPA disagrees with the suggested edits. EPA believes that the requirements for long-string casing are approp riate and offer appropriate flexibility: §146.86(b)(3) requires that the long- string casing extend to the inje ction zone and be cemented by circulating cement to the surface in one or mo re stages. It does not, however, specify how cementing would be accomplished, and gives flexib ility to the owner or operator to propose alternate methods to provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment, subject to the approval of the Director.

EPA stresses that protection of USDWs is the primary mission and mandate of the UIC program and the purpose of all requirements for inject ion wells. Any injection activity must be demonstrated to not endanger USDWs, regardle ss of their depth, and if such non-endangerment cannot be shown, then the activity will not be allowed under UIC requirements or the SDWA.

EPA disagrees that the requirement at §146.86(b) (4) should be deleted. Section 146.86(b)(4) of

the final rule allows alternate methods of staging the cement, at the Director's discretion, provided the owner or operator can demonstrate using logs that the cement does not allow fluid

movement behind the wellbore.

EPA does not believe that the cementing re quirements at §146.86 would prevent monitoring, operation, and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owne rs or operators of Class I hazar dous and Class I municipal waste disposal wells. Some of these wells, whic h must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Cl ass VI well construction requirements in the preamble to the final GS rule for additiona l 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/gr oundwater/uic/wells_se questration.cfm.

Letter ID: 0170 Comment ID: 24176 Letter Lines: 977 to 991

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

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)

Comment: Rule Provision: 146.86(b)(5)

API Comments: (5) Cement and cemen t additives must be compatible SUITABLE

FOR USE with the carbon dioxide stream a nd formation fluids and of sufficient quality and quantity to mainta in integrity over the design OPERATING life of the geologic sequestration project WELL. The integrity and location of the cement shall be verified using technol ogy capable of evalua ting cement quality radially and identifying the location of channels to en sure that USDWs are not endangered.

50Rationale: Experience with CO2 EOR under th e Class II program demonstrates the effectiveness of existing cementing mate rials and procedures. Standard API

cements have been used in numerous CO2 EOR operations with no adverse consequences. Refer to the citations w ithin EPA‘s proposed rule 73 FR 43532- 43533: Carey et al., (2007), Crow et al., (2008), and Meyer, J.P (2007).

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 th e 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 the post-injec tion site care period and beyond. While th e 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 cementing help ensure that the Class VI well will not serve as a conduit fo r movement of fluids associated with future injection operations.

EPA recognizes that the oil and gas industry has decades of e xperience injecting CO2 and has demonstrated the effectiveness of existing cem enting materials and procedures. The final GS rule, at §146.86(b)(1), specifies that all casing and cementing or other materials used in the

construction of Class VI wells must meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM Internat ional, or comparable standards acceptable to the Director. This requirement invokes the expe rtise of these bodies to ensure that the requirements for construction of Class VI wells re flect the state of the art in well construction technology. See the discussion of Cl ass VI well construction requirements in the preamble to the

final GS rule for additional information. A dditionally, EPA is developing guidance on the construction of Class VI wells. This guida nce will be available on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 24177 Letter Lines: 993 to 1010

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

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment)

Comment: Rule Provision: 146.86(c)(2)

API Comments: (ii) COMPOSITION of the carbon dioxide stream. (chemical content, corrosiveness, temperature, and density);

Rationale: There is no method for measurement of "corrosiveness" of a CO2

stream. The relevant information is the composition, not characteristics, of the CO2 stream. The composition of the CO2 stream is more relevant to the design of a tubing and packer system.

51Rule Provision: 146.86(c)(2)

API Comments: (iii) MAXIMUM PROPOSED Injection temperature and pressure; (iv) MAXIMUM PROPOSED Annular pressure; (v) MAXIMUM PROPOSED Injection rate (int ermittent or continuous) and volume of the carbon dioxide stream;

Rationale: Technical corrections.

Individual Response: As written, the text at §146.86(c)(3)(ii) accounts for all characteristics of the CO2 that could affect the performance of the tubing and packer, including the chemical content, corrosiveness, temperature, and de nsity. The suggested revision to refer to CO2 "composition" would be less precise. EPA clarifie s that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and describe d. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provid e valuable operational

information that the Director needs to determine appropriate standards for the tubing and packer.

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/groundwat er/uic/wells_se questration.cfm.

EPA has revised §146.86(c)(3)(iii) and (iv) to reference th e maximum proposed injection pressure and maximum proposed annular pressure, respectively. EPA has revised §146.86(c)(3)(v) to read "proposed in jection rate (intermittent or continuous), and volume and/or

mass of the carbon dioxide stream." EPA believes th at reference to the co ntinuous injection rate would be duplicative of the maximum rate. EPA believes that considering the maximum injection and annular pressure would be more protective.

Letter ID: 0170 Comment ID: 24178 Letter Lines: 1012 to 1039

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: Rule Provision: 146.87(a)

API Comments: (a) During the drilling and construction of a Class VI injection well, the owner or operator must run a ppropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic

formations to assure EVALUATE conformance with the injection well construction requirements under §146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests.

At a m inimum, such logs and tests must include: THE DIRECTOR MAY REQUIRE

52SUCH LOGS AND TESTS AS MAY BE NEED ED AFTER TAKING INTO ACCOUNT THE

AVAILABILITY

OF SIMILAR DATA IN THE AREA OF THE DRILLING SITE, THE CONSTRUCTION PLAN, AND THE

NEED FOR ADDITIONAL INFORMATION THAT MAY ARISE FROM TIME TO TIME AS

THE

CONSTRUCTION OF THE W ELL PROGRESSES AND THESE MAY INCLUDE THE

FOLLOWING:

Rationale: Obtaining the geologic inform ation will not assure conformance

with well construction re quirements, just measur e or evaluate it.

In well defined areas, these evaluatio ns are frequently unnecessary. The

Director should have discretion to select the appropriate requirements necessary

to obtain sufficient baseline data and information. For example, in an area where a number of wells are being dril led, the logging of su rface hole yields

little useful additional information.

In particular, this change would allow the Director to reduce the requirements when multiple wells are in stalled for a project.

Individual Response: EPA believes that all logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injec tion and confining zones an d ensure that the well is being drilled and cased as approved, and has me chanical integrity. This information is needed

to demonstrate that the well can be operated and tested in a ma nner that protects USDWs from endangerment. While the tests do provide information on some of the same items, each test provides unique pieces of information that build on each other and allow for interpretations not possible with a single test.

EPA notes that the Director ha s the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information, and the Dire ctor may accept information on cores of the injection and confining zones from nearby wells if the owner or operator can demonstrate that such cores are representative of conditions at the well in qu estion and core retrieval is not possible, as specified at §146.87(b) . EPA believes that logs and te sts must be performed on each well drilled regardless of existing information a bout the area to account for the complexity of CO2 injection well construction and the buoyanc y of CO2. Existing lithologic and geologic information may lack the details needed for site -specific well design a nd the geology needed to support protection of USDWs from endangerment.

Letter ID: 0170 Comment ID: 24180 Letter Lines: 1179 to 1215

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

Comment Code: 4110 2.4.1.1 Injection pressure limitations

Comment: Rule Provision: 146.88(a)

53API Comments: (a) Except during stimulati on, the owner or operator must ensure that injection pressure does not exceed 90 percent of the fr acture pressure of the injection zone so as to assure that the injection does not initiate new fractures or propagate exis ting fractures in the injection zone. In no case may injection pressure initiate fractures in the confining zone(s) or cause the movement of injectio n or formation fluids that endangers a USDW. (A) THE OWNER

OR OPERATOR MUST COMPLY WITH A MAXIMUM INJECTION PRESSURE LIMIT

APPROVED BY THE

DIRECTOR AND SPECIFIED IN THE PERMIT. IN APPROVING A MAXIMUM

INJECTION PRESSURE LIMIT, THE DIRECTOR SHALL CONSID ER THE RESULTS OF WELL TESTS AND,

WHERE APPROPRIATE, GEOMECHANICAL OR OTHER STUDIES THAT ASSESS THE RISKS

OF TENSILE

FAILURE AND SHEAR FAILURE. THE DIRE CTOR SHALL APPROVE LIMITS THAT,

WITH A REASONABLE DEGREE OF CERTAINTY, WILL AVOID INITIATION OR

PROPAGATION OF

FRACTURES IN THE CONFINING ZONE OR CAUSE OTHERWISE NONTRANSMISSIVE FAULTS

TRANSECTING THE CONFINING ZONE TO BECOME TRANSMISSIVE. IN NO CASE

MAY INJECTION

PRESSURE CAUSE MOVEMENT OF INJE CTION OR FORMATION FLUIDS IN A

MANNER PROHIBITED BY 40 CFR PART 144.12(A)

Rationale: API is concerned about three aspects of proposed section 146.88(a), governing injection pressure limitations. Fi rst, it "restricts" fractures in the injection zone "except during stimulation" rather than focusing on maintaining the integrity of the confining zone, which is what really matters for protecting USDWs. Second, it fails to refer specifi cally to the full ra nge of potential geomechanical failure modes potentially posed by operations at a particular site. Third, the type of geomechanical ri sk that is addressed (initiation or propagation of fractures), is dealt with in a potentially arbitrary fashion (the 90% of fracture pressure limit), which may not be appropriate in all cases.

The MSDG‘s recommended language addres ses these concerns by focusing on maintaining the integrity of the confining zone and including tensile failure and shear failure as transmissivity concerns. It calls for additional geomechanical studies of tensile failu re and shear failure only "where appropriate" because there will be loca tions where experience or existing information will provide sufficient eviden ce to avoid the need for additional studies. The need for conducting additi onal tests and for determining which tests would be acceptable is left to the Director‘s discretion.

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

54based on the fracture pressure of the injection zo ne, the limit is site-sp ecific and not arbitrary. EPA emphasizes that injection pressure limits ar e important to protect against fracturing of the confining zone, and that the requ irement at §146.88(a) that the pressure in th e injection zone not exceed 90 percent of the fracture pressure provides a margin of safety in the well operation and protects USDWs from endangerment. If the Dire ctor determines, based on a review of the information collected as part of site characterization, th at a lower injection pr essure limitation is appropriate in order to prevent endangerment of USDWs, the Director has the authority to set a lower limit in the operating permit than the limit established in the rule.

EPA notes that during the site characterization pr ocess, owners or operators must submit data about the geology of the site, as specified at §146.82(a), includ ing data on known or suspected faults and fractures and geomechanical informati on on fractures, stress, du ctility, rock strength, and in situ fluid pressures w ithin the confining zone. The Di rector will use these data to determine appropriate limits on injection.

In response to the concern about reopening of faults at lower pressures than 90 percent of fracture pressure, EPA believes that the requireme nt for the owner or operator to submit data on known or suspected faults and fractures and inform ation on the seismic history of the site will inform the determination of an appropriate pressu re limitation in the permit. Any sites with the potential for reopening or reactivation of faults or unacceptable seismic risk that could otherwise interfere with containment will not be permitted as GS sites.

EPA is developing guidance on site characterization for GS projects to assist owners or operators in meeting the requirements of §146.82 and to assist Directors in evaluating permit applications. The guidance will describe recommended approach es for characterizing the regional geology and hydrogeology of a proposed site and performing the necessary geochemical, geomechanical, and geophysical analyses of the injection and confin ing zone. EPA is also developing guidance for primacy agencies that will include recommended a pproaches for evaluating owner or operatorsubmitted data in setting permit conditions. The gu idance will be available on EPA's web site, at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 24181 Letter Lines: 1217 to 1221

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

Comment Code: 4100 2.4.1 Injection parameters

Comment: Rule Provision: 146.88(b)

API Comments: Injection OF THE CO2 STREAM between the outermost casing protecting USDWSs and the well bore is prohibited.

Rationale: Routine injection into zones other than the target interval(s) should be prohibited; however, wording of this requirement is not clear as to which interval is being addressed. An absolute prohibition on injection in to this annulus may also limit diagnostic options that could be

useful.

55Individual Response: EPA retains the provision as propos ed, and clarifies that injection between the casing and the well bore is prohibited. This is consistent with requirements for other injection well classes.

Letter ID: 0170 Comment ID: 24182 Letter Lines: 1223 to 1237

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

Comment Code: 4100 2.4.1 Injection parameters

Comment: Rule Provision: 146.88(c)

API Comments: (c) The owner or operator must fill the annulus between the tubing and the long string casing w ith a non-corrosive fluid approved by the Director. The owner or operator must maintain on th e annulus a pressure that exceeds the operating injection pressure, unless th e Director determines that such requirement might harm the integrity of the well. A POSITIVE PRESSURE ON THE

ANNULUS.

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

Positive annular pressure that exceeds th e operating injection pressure is not necessary because a leak from tubing to annulus does not have the same implications as in a Clas s I hazardous situation.

Individual Response: EPA believes that maintaining an annulus pressure that is higher than the injection pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the annulus fluid will move into the tubing, rather than the injectate moving out of the tubing and potentially along the outside of the well. EPA belie ves this requirement is appropriate for Class VI wells given the potential high volumes and superc ritical nature of the CO2 injectate, potential geomechanical stresses in the wellbore, and the potential for movement of the CO2 in the event of a mechanical integrity loss.

Letter ID: 0170 Comment ID: 24183 Letter Lines: 1239 to 1268

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: Rule Provision: 146.88(e)

API Comments: (e) The owner or operat or must install and use continuous recording devices to monitor: the inje ction pressure; the rate, volume, and temperature of the carbon dioxide stream and. THE OWNER OR OPERATOR MUST REGULARLY MONITOR the pressure on the a nnulus between the tubing and the long string casing and annulus fluid volume and. THE OWNER OR OPERATOR must

56install and use alarms and automatic down

- hole shut-off systems, designed to alert the operator and shutin the well when operating parameters such as injection rate, injection pressure, or othe r parameters approved by the Director diverge beyond ranges and/or grad ients specified in the permit;

Rationale: Over-pressure protecti on is best achieved by ensuring compatibility of the casing/tubing material design strength with the surface injection (compression) system. Down-hol e shut-in devices are not appropriate for this application. These devises are installed in the tubing string and are typically near the surface of the well. They‘re intended to seal the tubing in the event of catastrophic failure of th e wellhead. These devises would provide little if any protection to USDWs. Is not practicable to install these devises deep within the well (e.g. shortly above th e packer). Additiona lly these devises create a restriction on running other to ols like logging tools in the well and therefore could limit an operators ab ility to do required monitoring and diagnostic work. Lastly, these devises re quire periodic testing and maintenance which could require either pulling the device by wireline or by pulling the entire tubing string depending on the type of device installed. Either of these activities would be disruptive and costly to the overall project operations.

A more appropriate approach would be installation of landi ng nipples at appropriate points in the tubing string which would allow use of wireline retrievable plugs when needed.

Individual Response: EPA acknowledges that proper design of the well, including appropriate materials and emplacement of casing and tubing, is essential to proper operation of Class VI wells. Such design, however, does not eliminate the possibility of failure, e.g., due to overpressurization as suggested by the commenter. EP A believes that a multiple-barrier approach, which includes appropriate well design as required at §146.86, suitable injection pressure limits as required at §146.88(a), and automatic shut-off sy stems, as required at §146.88(e), is necessary to ensure protection of USDWs from endangerm ent from the risks asso ciated with CO2 GS.

Landing nipples, which are machined portions of the tubing that allow the seating of components–such as safety valves—at a later time, can be used to deploy safety valves after the initial well completion. EPA believe s, however, that if the shut-off system is not deployed until the failure occurs, CO2 will be free to flow out of the well until the shut-off valve is deployed. Since installing the new shut-off system will requ ire getting the device to the site, setting up a rig, and deploying the device down the well, a si gnificant amount of time could elapse following

an adverse event before the well is sealed. EPA believes that the risks of uncontrolled CO2 flow are too great to be allowed for such a length of time.

As described above, EPA will not require automatic down-hole shut-off devices for onshore Class VI wells since it is not necessary in a ll cases to ensure prot ection 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

57warrant their use. The rule requ ires, at §146.88(e)(3), that owners or operators of offshore wells

within State territorial waters install automatic down-hole shut-off systems. EPA believes that these requirements at §146.88(e) ensure that proper precautions are taken to prevent subsurface fluid movement and ensure protection of USDWs.

Letter ID: 0170 Comment ID: 24184 Letter Lines: 1270 to 1280

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: Rule Provision: 146.88(f)

API Comments: (f) If aN down

- hole automatic shutdown is triggered or a loss of mechanical integrity is discovered, the owner or operator must immediately investigate and identify as expeditio usly as possible the cause of the

shutoff. If, upon such investigation, th e well appears to be lacking mechanical integrity, or if monitoring required under paragraph (e) of this

section otherwise indicates that the well may be lacking mechanical integrity, the owner or operator must:

Rationale: Technical clarifi cation given changes above.

Individual Response: As described above, EPA will not require automatic down-hole shut-off

devices for onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from endangerment. Instead, the final rule , at §146.88(e)(2), requires that owners or operators of onshore Class VI wells install auto matic surface shut-off devices. The rule affords

Director's discretion to mandate automatic down-hole shut-off devi ces in onshore situations that may warrant their use. The rule requires, at §146. 88(e)(3), that owners or operators of offshore

wells within State territorial waters install auto matic down-hole shut-off systems. Please see the final rule and preamble for additional information on EPA's final approach.

Letter ID: 0170 Comment ID: 24185 Letter Lines: 1282 to 1286

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

Comment Code: 4000 2.4 Proposed Injection Well Operat ing Requirements (40 CFR 146.88)

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

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

No rationale provided

Individual Response: The final rule text at §146.88(f) now reads, "If a shutdown (i.e., downhole or at the surface) is triggere d or a loss of mechanical integr ity is discovered." Therefore the notice required at §146.88(f)(3) must be provide d within 24 hours of an automatic shut-off

58device being triggered or a loss of mechanical integrity being discovered. EPA believes this provision is necessary to ensure timely re sponse to potential USDW endangerment.

Letter ID: 0170 Comment ID: 24186 Letter Lines: 1288 to 1297

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

Comment Code: 4520 2.5.1 Continuous internal mechani cal integrity monitoring (seeking comment)

Comment Code: 4720 2.7.2 Operational record keeping and reporting

Comment: Rule Provision: 146.89(b)

API Comments: (b) To evaluate the abse nce of significant leaks under paragraph (a)(1) of this section, owne rs or operators must, following an initial annulus pressure test, continuously monitor AND RECORD AT LEAST DAILY, ANNULUS

PRESSURE

AND VOLUMES OF PACKER FLUID INJECTED OR REMOVED FROM injection pressure,

rate, injected volumes, and pressure on the annulus between THE tubing and long

stem STRING casing and annulus fluid volume as specifie d in §146.88 (e);

Rationale: Technica l clarification.

Individual Response: EPA agrees with the commenter regarding the importance of demonstrating internal mechanical integrity (M I), but disagrees with the suggested changes. Class VI injection wells must be equipped with dedicated computer-based continuous pressure monitoring devices in concert with the shut-off systems required for GS wells, which typically take readings several times per second (i.e., more frequently than daily) and record them electronically in a computer system. See §146.88. For additional information, please see the discussion of MITs in the final rule preamble.

EPA also disagrees that it is necessary to repor t volumes of packer fluid injected or removed. EPA agrees with the commenter that recordi ng annulus fluid volume may not be appropriate. EPA believes that knowing annulus fluid volum e (146.88(e)) is a necessary component of monitoring well mechanical integr ity, but believes that knowing the annulus fluid volume added is sufficient to meet the intent of the requireme nt. The final GS rule requires that owners or operators use continuous recordi ng devices to monitor injection pressure, rate, and volume, as well as the pressure on the annulus between the tubing and the long string casing. It also modifies the requirement in the proposed rule to continuously monitor annulus fluid volume; it now requires recording of annulus flui d volume added. See §§146.88(e); 146.89(b); and 146.90 (b).

The final rule includes the suggested change from “long-stem” to “long-string” casing.

59Letter ID: 0170 Comment ID: 24188 Letter Lines: 1320 to 1336

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

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 CFR 146.90)

Comment: Rule Provision: 146.90(b)

API Comments: (b) Installation and use, ex cept during well wor kovers as defined in §146.86 8(d), of continuous recording MONITORING devices (INCLUDING DIGITAL DEVICES CAPTURING PERIODIC DATA) to monito r injection pressure, rate and volume; AND RECORD AT LEAST DAILY the pressure on the annulus between the tubing and the long string casing; and th e annulus fluid volume;

Rationale: §146.86(d) does not exist; perh aps §146.88(d) is what was apparently

intended.

There is concern regarding what cons titutes continuous monitoring. Industry agrees that regular monitoring of th e parameters identified by EPA is appropriate. Our experience with CO2 EOR st rongly shows that daily monitoring of most of these parameters is adequate (e xceptions to this would be on a sitespecific basis). Recording should genera lly be done on a daily basis and reporting on a semi-annually basis.

Individual Response: EPA believes that a monitoring regime that includes cont inuous pressure monitoring of GS wells, as re quired at §146.88(e), is important and appropriate because the potentially corrosive nature of CO2 streams in the presence of water makes it critical to immediately identify corrosion-related well mechanical integrity loss.

Regarding the question of what constitutes cont inuous monitoring, EPA expects that Class VI injection wells under §146.88(e) wi ll be equipped with dedicated computer-based continuous pressure monitoring devices (in concert with th e Director-approved shut -off systems required for GS wells), which typically take readings several times per second and record them electronically in a computer system. EPA did not specify the types of devices in th e final rule, however.

EPA adds that the final GS rule referen ces §146.88(e), as the co mmenter suggests.

Letter ID: 0170 Comment ID: 24189 Letter Lines: 1338 to 1353

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

Comment Code: 4630 2.6.3 Corrosion monitoring

Comment: Rule Provision: 146.90(c)

API Comments: (c) WHERE CONDITIONS WA RRANT, corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting and other signs of

60corrosion must be performed on a AND RECORDED AT LE AST quarterly basis WHICH MAY BE MODIFIED TO BE LESS FREQUENT AS APPROVED BY THE

DIRECTOR BASED ON CONSTRUCTION MATERIALS, OPERAT ING CONDITIONS, AND MONITORING

HISTORY to ensure that the well components meet the minimu m standards for material strength and performance set forth in §146.86(b) by:

Rationale: Technical correction. API questions the need for corrosion monitoring of most injected CO2 streams since they will typically be nearly pu re and dry thus having no corrosive properties. Industry experi ence with production, transp ortation, and injection of dry CO2 strongly illustra tes the non-corrosive nature of this type of CO2

stream.

Individual Response: EPA believes that corrosion monitoring is warranted and necessary for all Class VI wells in order to protect USDWs. CO2 in the presence of water (including water with NOx, SOx, and H2S impurities) can be corrosive to well materials and cements. Thus, although a CO2 stream may be dry, the pot ential for corrosion of well materials down-hole, where the injectate can potentially mix w ith water in the target form ation, 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 betw een cement and CO2-saturated brine.

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 related to the effect s 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,

61most 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)).

Letter ID: 0170 Comment ID: 24190 Letter Lines: 1355 to 1364

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

Comment Code: 4630 2.6.3 Corrosion monitoring

Comment: Rule Provision: 146.90(c)

API Comments: (1) Placing ANALYZING coupons of the well construction materials PLACED 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 AND INSPECTI NG THE MATERIALS IN THE LOOP; or (3) Using an alternative method, MATERIALS, OR TIME PERIOD approved by the Director;

Rationale: Clarifying edits.

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. See the final rule and preamble for furthe r discussion on EPA's final approach.

Letter ID: 0170 Comment ID: 24191 Letter Lines: 1366 to 1385

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

Comment Code: 4660 2.6.6 Geochemical monitoring

Comment: Rule Provision: 149.90(d)

API Comments: (d) Periodic monitoring of the ground water FORMATION FLUID quality and geochemical changes above IN A PERMEABLE AND POROUS FORMATION AS NEAR AS PRACTICABLE TO the confining zone(s) FOR GEOCHEMICAL CHANGES that may be

a result of carbon dioxide OR DISPLACED FORMATION FLUID movement through the confining zone or addi tional identified zones: (1) The location and number of monitoring wells must be based on specific information about the geologic sequestrati on project, including injection rate and volume, geology, the presence of artific ial penetrations and other RELEVANT factors AS WARRANTED BY A RISK-ASSESSMENT; (2) The monitoring frequency and spatial distribution of monitoring wells must

62be based on GEOLOGICAL, geoche mical AND GEOPHYSICAL data that has been collected under § 146.82(a)(6) §146.82(D) and any modeling re sults in the area of

review evaluation re quired by §146.84(b);

Rationale: Drilling monitoring wells should be carefully considered since each well introduces a potential pathway for movement. In addition the cost of adding multiple wells could create a barrier to CCS development, while providing

limited information on actual movement of the CO2 stream.

Individual Response: EPA agrees that monitoring plans and methods need to be site-specific and believes that the monitoring requirements for GS sites at §146.90 provide an appropriate level of flexibility in structuring a testing and monitoring plan that protects USDWs from endangerment, while addressing the needs sugge sted in the commenter’s proposed edits.

Regarding monitoring locations, section §146.90(d) requires periodic monitoring of the ground water quality and geochemical changes above the confining zone(s). EPA clarifies that this monitoring requirement does not include the c onfining layer itself. Monitoring above the confining layer will provide an indication of upward movement of CO2 that might endanger a

USDW. The exact number of formations to be te sted must, however, be based on site-specific

characteristics and vulnerabilities and described in the Director-approved testing and monitoring plan.

To mitigate the risk of fluid movement, EPA re quires owners and operators to submit a testing and monitoring plan that describes how the ow ner or operator plans to site and construct monitoring wells.

EPA believes, however, that monitoring using we lls in the injection zone, e.g., for pressure monitoring as required at §146.90(g)(1), can be safe ly performed if the we lls are constructed to prevent flow between the injection zone and US DWs or other layers a bove the confining zone. Such construction technologies ex ist and have been used in the oil and gas industry for years. EPA believes that properly constructed monitoring wells will be a safe way to obtain the data that is essential to ensure that the injected CO 2 remains confined in the injection zone and that pressure changes are not causing movement or form ation of other fluids. To mitigate the risk of fluid movement, EPA requires owners and operators to submit a testing and monitoring plan that describes how the owner or operator plans to site and construct monitoring wells. EPA is developing guidance on well constr uction that will include reco mmendations for monitoring well construction. The guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

EPA is developing guidance on testing and mon itoring to assist owne rs or operators and Directors in evaluating requi rements under §146.90, including pr oposed monitoring plans. The guidance describes available technologies a nd recommended approaches for implementing a testing and monitoring plan, including pre-ope rational geophysical l ogging and testing of injection wells, MITs, injecti on well testing during operation, groundwater quality monitoring, tracking the CO2 plume and pressure front, a nd soil gas and surface air monitoring which may be required by the UIC Director for specific GS projects. Th e guidance can be found on EPA’s

63website at http://water.epa.gov/type/gr oundwater/uic/wells_sequestration.cfm.

EPA acknowledges the commenters' concern abou t the cost of monitoring. However, EPA believes that monitoring is essential for protecti on of USDWs at GS site s. Although a significant cost in absolute terms, monito ring costs are expected to be a small fraction of site operating costs, according to EPA's cost analysis for the GS rulemaking (which is av ailable in the docket).

Letter ID: 0170 Comment ID: 24192 Letter Lines: 1299 to 1318

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

Comment Code: 4540 2.5.2 Proposed external MIT requirements

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment)

Comment: Rule Provision: 146.89(c)

API Comments: (c) At least once per year, the owner or operator must confirm the absence of significant fluid movement unde r paragraph (a)(2) of this section

USING A METHOD ACCEPTABLE TO THE DI RECTOR (E.G. INCLUDING DIAGNOSTIC

SURVEYS

SUCH AS OXYGEN-ACTIVATI ON LOGGING OR TEMPERATURE OR NOISE LOGS). (1) A tracer survey such as oxygen

- activation logging; (2) A temperature or noise log; or (3) A casing inspection log, if required by the

Director.

Rationale: Revised text supports a perfor mance-based approach and allows the development and use of new technologies as they become av ailable. Cement

circulation to the surface is not neces sary because having the open annulus above the top of cement allows regular monitoring of annular pressure which could indicate leakage.

Subsection (3) was deleted because it re quires the tubing to be pulled at significant cost and risk of uncontrolled releases.

Individual Response: EPA believes that the MITs describe d in §146.89(c) of the rule (e.g., an approved tracer log or temperatur e or noise logs) are effective me thods to demonstrate external MI, provide an important early warning of potenti al problems in the injection well system, and represent standard techniques that have been used successfully by the drilling industry and for the UIC Program for decades. The Agency notes th at the regulations do provide the Director the flexibility at §146.89(e) to approve th e use of alternative MIT methods.

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind the casing, but clarifies that it is appropriate to be used to determine the presence or absence of corrosion of the long-string casing, and is required if the Director determines that it is necessary based on site-specific information. EPA ha s revised the final GS rule to require that

64the frequency of the casing insp ection log must be specified in the approved testing and monitoring plan. See §146.89(d).

Letter ID: 0170 Comment ID: 24193 Letter Lines: 1387 to 1396

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

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 CFR 146.90)

Comment: Rule Provision: 149.90(e) - (f)

API Comments: (e) A demonstration of exte rnal mechanical integrity pursuant to §146.89(c) at least once per year UNTIL THE WELL IS PLUGGED; (f) IF CONDITIONS WARRANT, A pressure fa ll-off test OR OTHER EQUIVALENT TEST

THAT IDENTIFIES RESERVOIR CONDITI ONS WITH RESPECT TO FLOW DYNAMICS

at least once every five years unless more frequent te sting is required by th e Director based on site specific information;

Rationale: Technical clarifications.

Individual Response: Regarding pressure testing, EPA believe s that pressure fall-off testing is necessary for GS wells. Pressure fall-off tests are designed to verify that modeled projections of reservoir pressure decline agree with measured pressure declin e profiles. These tests can be

useful in AoR calculations and reevaluations and may also indicate mischaracterization of site geology and the presence of leakage pathways. Ther efore, EPA is requiring that pressure fall-off testing be conducted every five years at a minimu m, and the final GS regulation includes this requirement at §146.90(f). Pressure fall-off tests may be conducted in conjunction with other well performance tests (i.e., mechanical integrity te sting) to ensure safe and effective operations. EPA disagrees that the rule shoul d provide specifics of the test at the degree suggested, however.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisi ons to the GS Rule. S ee the final rule and preamble for further discussi on on EPA's final approach.

Letter ID: 0170 Comment ID: 24194 Letter Lines: 1398 to 1410

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

Comment Code: 4650 2.6.5 CO2 plume and pressure fr ont tracking (seeking comment)

Comment: Rule Provision: 149.90(g)

API Comments: (g) Testing and monitoring AS APPROPRIATE TO SUPPORT THE MODEL

FOR

65to trackING the extent of the carbon di oxide plume and the position of the pressure front. by either monitoring for pressure changes in the first formation overlying the confining zone or using indirect, geophysical techniques (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down

- hole carbon dioxide detection tools);

Rationale: Monitoring outside of the inje ction zone provides little information of value for tracking and mon itoring the injected plume. Ex amples of how to test

and monitor could be included in the Pream ble but need not be included in the

rule itself.

Individual Response: EPA has revised this requirement in the final rule. The final GS regulation, at §146.90(g)(1), requires all GS project owners or opera tors to monitor for pressure changes in the injection zone. EPA believes that pressure monitoring in the injection zone is necessary to track the development and moveme nt of the pressure front and CO2 plume.

Pressure monitoring within the injection zone is necessary because any such monitoring above the confining zone would not de tect movement of the pressure front unless a breach of the confining zone occurs. EPA believes that monitori ng using wells in the inje ction zone (i.e., that penetrate the confining zone) can be safely performed if the wells are constructed to prevent flow between the injection zone a nd USDWs or other layers above the confining zone. Such construction technologies exist and have been us ed in the oil and gas industry for years. EPA believes that the benefits of monitoring in the injection formation outweigh the manageable risk of those monitoring wells serving as conduits for fluid movement. EPA adds that owners or operators may consider performi ng additional pressure monitoring in wells that are above the confining zone (e.g., in the same wells used to perform ground water quality monitoring required at §146.90(d)) to provide additional verification that no pressure ch anges are occurr ing above the confining zone due to CO2 leakage. Monitoring al so identifies needed re medial actions, provides inputs for AoR reevaluation modeling, and ta rgets additional geochemical and surface monitoring needs. Knowledge of th e location of the CO2 plume and the associated pressure front will assure the public that GS projects are proceeding according to plan, provide sufficient information to the owner or operator and Director, or allow for appropriate actions to address any

indication that USDWs may be endangered.

EPA acknowledges that, at certain sites, there ma y be a need for more or different monitoring schemes (which may include monitoring in the conf ining zone), and adds that it is important to balance the need for adequate monitoring that ensures USDW protection from endangerment against too many artificial penetrations which c ould serve as conduits for fluid migration. EPA expects site-specific testing and monitoring plan s to describe the proposed monitoring regime, which must be approved by the Director. Flexibility is also provided re garding how to monitor for the sp ecific data required by the final rule. The testing and monitoring plan is develope d by the owner or operato r in consultation with the Director and is designed to ensure that a detailed, Director-approved document describing how monitoring will be conducted during the lifetime of the project exists.

EPA is developing guidance on testing and mon itoring to assist owne rs or operators and

66Directors in evaluating requi rements under §146.90, including pr oposed monitoring plans. The guidance describes available technologies a nd recommended approaches for implementing a testing and monitoring plan, including pre-ope rational geophysical l ogging and testing of injection wells, MITs, injecti on well testing during operation, groundwater quality monitoring, tracking the CO2 plume and pressure front, a nd soil gas and surface air monitoring which may be required by the UIC Director for specific GS projects. Th e guidance can be found on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_se questration.cfm.

Letter ID: 0170 Comment ID: 24195 Letter Lines: 1412 to 1419

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

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking comment)

Comment: Rule Provision: 146.90(h)

API Comments: (h) At the Di rector’s discretion BASED ON SITE-SPECIFIC CONDITIONS AND RISK-BASED FACTORS, surface air mon itoring and/or soil gas monitoring to

detect movement of carbon dioxide that could endanger a USDW.

Rationale: In most situations soil an d air monitoring does not provide an effective method of protecting USDWs.

Individual Response: EPA clarifies that subsurface geochemi cal and pressure monitoring in the

subsurface formations are the first line of m onitoring that would allow detection of potential endangerment to USDWs from GS ac tivities (this is required at al l GS sites, as described at §146.90(d)). The Agency also believes that surf ace air and soil gas monitoring, when coupled with subsurface monitoring, may be appropriate at some GS projects to ensure USDW protection.

The final rule at §146.90(h) retains the allowance for surface air and soil gas monitoring at the

discretion of the Director as a means of identif ying leaks that may pose a risk to USDWs and informing emergency notification of a Class VI ow ner or operator and UIC Director in the event of a USDW endangerment, pursuan t to requirements at §146.91(c).

The selection of monitoring methods will be s ite-specific (e.g., may be influenced by geology, injection depth, and operational conditions) and must be based on poten tial risks to USDWs

within the AoR.

Letter ID: 0170 Comment ID: 24196 Letter Lines: 1421 to 1427

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

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment)

Comment: Rule Provision: 146.90(h)(1)

67API Comments: (1) The test ing and monitoring plan mu st be based on potential

vulnerabilities SITE-SPECIFIC GEOLOGIC FACT ORS, MODELING, AND RISKASSESSMENT within the area of review;

Rationale: Technica l clarification

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. See the final rule and preamble for further discussi on on EPA's final approach. EPA anticipates that the testing and monitoring plan will address site-sp ecific geologic factors, modeling, and riskassessment. EPA is developing guidance on how be st to develop the various required project plans, including the testing and monitoring pla n. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 24197 Letter Lines: 1429 to 1437

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

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment)

Comment: Rule Provision: 146.90(i)

API Comments: (i) Any addi tional monitoring, as require d by the Director, BASED

ON SITE-SPECIFIC CONDITIONS AND RISK-BAS ED FACTORS, necessary to support, upgrade, and improve computational modeli ng of the area of review evaluation required under § 146.84(b) and to determin e compliance with st andards under 40

CFR 144.12

Rationale: Technica l clarification

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. See the final rule and preamble for further discussi on on EPA's final approach. EPA agrees that any additional monitoring requirements would be base d on site-specific geol ogic factors, modeling, and risk-assessment. EPA is developing guida nce for directors that provides recommended approaches when exercising discretion to requ ire additional monitoring. The guidance can be found on EPA’s website at http:/ /water.epa.gov/type/groundwater/ uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 24198 Letter Lines: 1439 to 1463

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

Comment Code: 4720 2.7.2 Operational record keeping and reporting

Comment: Rule Provision: 146.91(a)

68API Comments: (a) Semi-annual OR LESS FREQUENT AT THE DISCRETION OF THE

DIRECTOR reports containing: (1) Any SIGNIFICANT changes to the phys ical, chemical and other relevant

characteristics of the carbon dioxide str eam from the proposed operating data;

Rationale: Over the life of the project, the Director may decide that less reporting is acceptable

(1) Technical clarification. Significance can be determined by a statistical analysis of the data. Rules should recogni ze that there will be minor variations in many data sets over time.

Rule Provision: 146.91(a)

API Comments: (3) A descrip tion of any SIGNIFICANT even t that exceeds operating parameters for annulus pressure or inj ection pressure as specified in the permit; (4) A description of any SIGNIFICANT ev ent which triggers a shutdown device required pursuant to §146.88(e) and the response taken;

Rationale: EPA should consider some signi ficance threshold on reporting these events to avoid reporting events that would be of limited interest or

consequence.

Individual Response: EPA disagrees that less frequent than semi-annual reporting is appropriate to protect USDWs from endangerment. The Agency believes se mi-annual reporting is appropriate and necessary for Class VI wells during the operational phase of the project. EPA believes that the potentially large injection volume s and injection pressure s associated with GS warrant more frequent reporting th an for other well classes. See th e final rule and preamble for further discussion on EPA's final appr oach to testing and monitoring.

EPA also retained the provision at §146.91(a)(3 ) as proposed. The final rule at §146.91(a)(3) requires reporting of all exceedances of operating parameters. EPA disagrees with the suggestion to report only "significant" exceedances. Making a determination as to whether an exceedance is "significant" is not the purpose of the requirement. EPA believes that the ability of an operator toconsistently meet operating requirements and avoid exceedances provides evidence of a wellmanaged GS project that is in compliance with the Class VI permit. If multiple exceedances occur, the Director should be aware of such occurrences, determine whether these indicate problems at the site, and determine the appropr iate course of action (e.g., a well workover, modification of operating parameters, or imposition of a penalty).

Letter ID: 0170 Comment ID: 24199 Letter Lines: 1465 to 1473

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

69Comment Code: 5100 2.8.1 Injection well plugging activ ities (seeking comment) (40 CFR 146.92)

Comment: Rule Provision: 146.92(a)

API Comments: (a) Prior to the well plugging, the owner or operator must flush each Class VI injection well with a buffe r fluid, determine bottomhole reservoir pressure, and perform a final EXTERNAL mech anical integrity te st OF ANY RELEVANT

WELLBORE MATERIALS REMAINING.

Rationale: Many of the components that woul d be tested by an internal MIT are removed or tested during the plugging process.

Individual Response: EPA agrees that only an external MIT is required, and has modified the GS rule at §146.92(a) to require owners or opera tors to perform a final external mechanical integrity test prior to the well plugging.

Letter ID: 0170 Comment ID: 24200 Letter Lines: 1475 to 1481

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: Rule Provision: 146.92(b)(2)

API Comments: (2) Appropria te testing methods to ensure FINAL EXTERNAL mechanical integrity as specified in §146.89(C);

Rationale: Many of the components that woul d be tested by an internal MIT are removed or tested during the plugging process.

Individual Response: EPA agrees that only an external MIT is required, and has modified the GS rule at §146.92(a) to require owners or opera tors to perform a final external mechanical integrity test prior to the well plugging.

Letter ID: 0170 Comment ID: 24201 Letter Lines: 1483 to 1489

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: Rule Provision: 146.92(b)(5)

API Comments: (5) The type and grade and quantity of material to be used in plugging. The material must be SUITABLE FO R USE with the car bon dioxide stream;

70and

No rationale provided

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 retains this requirement.

Letter ID: 0170 Comment ID: 24202 Letter Lines: 1491 to 1501

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

Comment Code: 4730 2.7.3 Reporting associated with closur e and post-injection site care

Comment Code: 5100 2.8.1 Injection well plugging activ ities (seeking comment) (40 CFR 146.92)

Comment: Rule Provision: 146.92(d)

API Comments: (d) Plugging report. Within 60 days after plugging the owner or operator must submit a plugging report to the Director. If the semi

- annual report is due less than 15 days after completion of plugging, then the report

m ust be submitted within 60 days after plugging. The report must be certified as accurate by the owner or operator and by the person who performed the plugging operation (if other than the owner or operator.)

Rationale: The proposed changes are s uggested to simplify and clarify a provision that API believes is needlessly complicated.

Individual Response: EPA has revised the text at §146.92(d) to reduce confusion. The final rule text reads, "Within 60 days after plugging, the owner or operator must submit a plugging report

to the Director."

Letter ID: 0170 Comment ID: 24203 Letter Lines: 1503 to 1511

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

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities

Comment: Rule Provision: 146.93(a)(1)

API Comments: (1) The owner or operat or must submit the postinjection site care and site closure plan as a part of the permit applicati on to be approved by

the Director. SHALL CONTINUE TO CONDUCT M ONITORING AS SPECI FIED IN THE

DIRECTOR-APPROVED POST-INJECTION SITE CARE AND SITE CLOSURE PLAN,

PURSUANT TO

THE PERFORMANCE BASED CRITERIA DESCRIBED IN 146.93(B)(3).

71Rationale: Revisions here refl ect changes to §146.93(b)(3)

Individual Response: EPA disagrees with the suggested ch anges, and disagrees that the postinjection monitoring period should be strictly pe rformance-based. The Agency agrees that there

will be limited circumstances where it can be dem onstrated in less than 50 years that the plume and pressure front no longer pose a risk of endangerment to USDWs, and has included requirements in the final Class VI rule at §146.93 (c) for an owner or operator to substantially

demonstrate that an alternative time frame en sures the protection of USDWs. However, EPA anticipates that a default timeframe for post-injecti on site care will necessary for most GS sites to ensure the protection of USDWs. A 50-year post-injection site care timeframe represents a reasonable and protective monitoring period base d on a review of research studies, industry reports, and existing environmental programs, and evaluation of public comments. For this reason, the final GS regulation includes a provi sion that the Director may, at his or her discretion, shorten the post-inj ection site care timeframe if the owner or operator can demonstrate that the GS project does not pose an endangerment to USDW s, as specified in §146.93(b)(2). Such a demonstration will be site-s pecific, and based on pressure monitoring and USDW impacts.

The GS rule requires owners or operators to submit a post-injection site care and site closure plan as part of the permit application, as specified in §146.82(a), in order to outline how these activities will be performed and how non-enda ngerment of USDWs will be demonstrated throughout the post-injec tion site care period.

Letter ID: 0170 Comment ID: 24204 Letter Lines: 1513 to 1527

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: Rule Provision: 146.93(a)(2)

API Comments: (2) The post

- injection site care and site closure plan must include the following information: (i) The pressure differential betw een preinjection and predicted post

- injection pressures in the injecti on zone; (ii) The predicted position of the carb on dioxide plume and associated pressure

front at site closure as de monstrated in the area of review evaluation required under § 146.84(b); (iii) A description of post

- injection monitoring location, metho ds, and proposed frequency; and (iv) A proposed schedule for submitting post

- injection site care monitoring

results to the Director.

Rationale: Revisions here refl ect changes to §146.93(b)(3)

Individual Response: Based on its evaluation of all public comments and input on the proposed

72rule and NODA and Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and preamble for furthe r discussion on EPA's final approach.

Letter ID: 0170 Comment ID: 24205 Letter Lines: 1529 to 1535

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

Comment Code: 4730 2.7.3 Reporting associated with closur e and post-injection site care

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93)

Comment: Rule Provision: 146.93(a)(4)

API Comments: (4) AT ANY TIME DURING THE POST-INJECTION SITE CARE PHASE,

The owner or operator may modify and resubmit the post-injection site care and site closure plan for the Director‘s approv al within 30 days of such change.

Rationale: Technical Clarification.

Individual Response: EPA agrees that a post-injection site care monitoring plan is an important tool for GS, and anticipates that, in some cases, the appropriate post-injection monitoring strategy may end up being different than initially proj ected, and there may be a need to amend the post-injection site care and site closure plan. EPA is requi ring that upon the cessation of injection, the owner or operator submit an amended post-injection si te care and site closure plan or demonstrate to the Director that no changes to the original post-injection site care and site closure plan are necessary ( §146.93(a)(3)). EPA is not requiri ng formal periodic review and updates to the PISC and site cl osure plan throughout the injec tion phase. EPA does not expect that changes to this plan would be implemente d until injection operations cease. EPA envisions that owners or operators would take into accoun t similar considerations that guide updates to other project plans, e.g., monito ring and operational data and resu lts of AoR reevaluations. EPA adds that, if any monitoring or other site data indicate a need for amending the post-injection site care plan, the owner or operator is exp ected to amend the plan accordingly.

EPA adds that, in the final rule, it has revise d the text at §146.93(a)(4) as follows: "At any time during the life of the geologic sequestration pr oject, the owner or ope rator may modify and resubmit the post-injection site car e and site closure plan for th e Director’s approval within 30 days of such change."

EPA is issuing guidance on development and upda ting of the GS project plans, including the post-injection site care and site closure plan. The guidance will be available on EPA's web site, at http://water.epa.gov/type/ground water/uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 24206 Letter Lines: 1537 to 1585

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

73Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment)

Comment: Rule Provision: 146.93(b)

API Comments: (b) The owner or operator shall monitor the site following the cessation of injection to show the position of the carbon dioxide plume and pressure front and demonstr ate that USDWs are not bei ng endangered. (1) The owner or operator shall continue to conduct monitoring as specified in the Director-approved post-injection site care and site closure plan, for at least 50 years following the cessation of injection. At the Director‘s

discretion , the monitoring will continue until the geologic sequestration project no longer poses an endangerment to USDWs. UNTIL CLOSURE IS AUTHORIZED PURSUANT TO §146.93(B)(3). (2) If The owner or operator can request a nd demonstrate to the satisfaction of the Director before 50 years, based on monitoring and other site

- specific data, that the geologic sequestration pr oject no longer poses an endangerment to USDWs, the Director may approve an amendment to THAT the post-injection site care and site closure plan SHOULD BE REVISED to reduce the frequency of monitoring or may authorize site closure before the end of the 50

- year period.

Rationale: API, along with the MSDG, belie ves there are three problems with the closure standard in proposed section 146.93(b). First, the presumption that monitoring should continue for 50 years is unnecessary and c ounterproductive. A straight performance standard is preferab le to this or any other fixed time period because it provides a clearer standa rd and an incentive to maximize the understanding of site and proj ect performance and as such is more protective of USDWs. Second, the proposal requires a showing that the CO2 plume has "stabilized", which is undefined. Cessation of plume movement is not necessarily essential to show that a pr oject poses no threat of endangerment to USDWs-plumes that are still moving may, nonetheless, remain contai ned. Instead, it is more protective to show that the plume is not expected to encounter a leakage pathway. Third, the required showing that "no additional monitoring is needed" does not provide guidance regarding how an operator is to show that no additional monitoring is needed. The pr oposal below provides specific guidance on what the operator must show.

API, in concert with the MSDG, reco mmends the standard in the proposed alternative language for section 146.93(b) below because it sets forth detailed criteria, all of which must be satisfied, to demonstrate that the site does not pose an endangerment to USDWs. The specific criteria listed in our proposal will serve to provide the Director with th e requisite information to make the appropriate determination. The advantage of this approach is that it establishes clear criteria that an operator must demonstrate before obtai ning site closure based upon particular site characteris tics and is, therefore, reasonably applicable to any storage site as opposed to a standard based upon a

74fixedduration. Furthermore, it is more stringent than a pur ely discretionary approach because it establishe s specific criteria that mu st be shown before site closure may be granted. We believe this la nguage, which is an extension of work done by the World Resources Institute a nd the Ground Water Protection Council, avoids the noted shortcomings and pr ovides stronger protec tion for USDWs.

Individual Response: EPA disagrees with the suggested changes. As noted above, EPA disagrees that a post-inj ection site care timeframe of 50 year s is excessive for most Class VI wells. EPA believes that a 50-year default post- injection site care timeframe, as required at §146.93(b)(1), is not overly burdensome, does not ex aggerate the risks associated with GS, is consistent with other environmental program s, and sufficiently 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 Class VI rule offers owners or operators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe durin g the PISC period based on site-specific data, pursuant to requirements at §146.93(b) ; or (2) affording the Director discretion to allow a Class VI well owner or operator to demonstrate, based on substantial data during the permitting process, that an alternative PISC timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to requirements at §146.93(c). EPA believes that a 50 year pos t-injection site care timeframe represents a reasonable and protective monitoring period and available data, including data submitted by commenters, do not support a different default timeframe. Furthermor e, EPA believes that a 50-year default postinjection site care timeframe, as required at §146.93(b)(1), is not overly burdensome, does not exaggerate the risks associated with GS, is consistent with other environmental programs, and sufficiently protects USDWs from endangerment.

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 required under 146.92 and 146.93. The guidance describes recommended approaches for how an owner or operator could plug injection and monitoring wells, perform post-injection monitoring, demonstr ate the appropriateness ofan alternative postinjection site care time frame, demonstrate non-endangerment, and perform site closure activities. This guidance will be available at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

Letter ID: 0170 Comment ID: 24207 Letter Lines: 1572 to 1585

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations

Comment: API, in concert with the MSDG, reco mmends the standard in the proposed alternative language for section 146.93(b) below because it sets forth detailed

75criteria, all of which must be satisfied, to demonstrate that the site does not pose an endangerment to USDWs. The specific criteria listed in our proposal will serve to provide the Director with th e requisite information to make the appropriate determination. The advantage of this approach is that it establishes clear criteria that an operator must demonstrate before obtai ning site closure based upon particular site characteris tics and is, therefore, reasonably applicable to any storage site as opposed to a standard based upon a fixedduration. Furthermore, it is more stringent than a pur ely discretionary approach because it establishe s specific criteria that mu st be shown before site closure may be granted. We believe this la nguage, which is an extension of work done by the World Resources Institute a nd the Ground Water Protection Council, avoids the noted shortcomings and pr ovides stronger protec tion for USDWs.

Individual Response: EPA believes that many site-speci fic factors will influence the determination of when the CO2 plume and pressu re front no longer pose a risk of endangerment to USDWs, and therefore is not defining the criteri a in the final rule. It is for this reason that EPA believes that individual UIC Directors, in c onsultation with operators, will be in the best position to determine whether additional post-inje ction site care is needed. EPA expects this

decision to be made based on relevant site data and in consultation with all potentially impacted parties.

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the guidance will assist Directors in evaluating 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 monitoring wells, perform post-injection monitorin g, demonstrate non-endangerment, and perform site closure activities. The guidance will be available at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

Letter ID: 0170 Comment ID: 24208 Letter Lines: 1587 to 1622

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

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations

Comment: Rule Provision: 146.93(b)(3)

API Comments: (3) Prior to authorization fo r site closure, the owner or operator
MUST submit to the Director a demonstration , DEMONSTRATE TO THE DIRECTOR, based on monitoring, and other site-specific data, AND MODELING THAT IS

REASONABLY CONSISTENT WITH SITE PERFORMANCE that the carbon dioxide plume

and pressure front have stabilize d and that no additional monitoring is needed to assure that the geologic sequestration pr oject does not AND IS NOT EXPECTED TO pose an endangerment to USDWs. THE DI RECTOR SHALL APPROVE CLOSURE IF THE

76OWNER OR OPERATOR DEMONSTRATES, BASE D ON THE CURRENT UNDERSTANDING OF THE SITE,

INCLUDING MONITORING DATA AND/OR MODELING, ALL OF THE FOLLOWING: (I)

THE

ESTIMATED MAGNITUDE AND EXTENT OF THE PROJECT FOOTPRINT (CO2 PLUME

AND THE AREA OF ELEVATED PRESSURE), (II) THE ESTI MATED LOCATION OF THE DETECTABLE CO2 PLUME; (III) THAT THERE IS NO SIGNIFICANT LE AKAGE OF EITHER CO2 OR DISPLACED

FORMATION FLUIDS THAT IS ENDANGERING USDWS; (IV) THAT THE INJECTED OR DISPLACED

FLUIDS ARE

NOT EXPECTED TO MIGRATE IN THE FU TURE IN A MANNER THAT ENCOUNTERS

A POTENTIAL

LEAKAGE PATHWAY INTO A USDW; (V) THAT THE INJE CTION WELLS AT THE SITE

COMPLETED

INTO OR THROUGH THE INJECTION Z ONE OR CONFINING ZONE ARE PLUGGED

AND ABANDONED IN ACCORDANCE WITH THESE REQUI REMENTS; AND (VI) ANY REMAINING

PROJECT MONITORING

WELLS AT THE SITE ARE BEING MANAGE D BY A PERSON AND IN A MANNER

ACCEPTABLE TO

THE DIRECTOR.

Rationale: API edits establish the performance based criteria for selecting the monitoring period. EPA should recognize th at under any given set of site specific conditions some of these criter ia may not be fully satisfied. EPA should retain the ability to waive indivi dual monitoring criteria described here

to reflect that situation.

Rule Provision: 146.93(b)(4)

API Comments: (4) If such a dem onstration cannot be made (i.e. , if the carbon dioxide plume and pressure front have not stabili zed) after the 50

- year period, the owner or operator must submit to th e Director a plan to continue post

injection site care.

Rationale: No longer necessary given changes above.

Individual Response: EPA disagrees that the rule should specify the criteria for setting the monitoring timeframe. Instead, EPA believes that such determinations are site-specific and should be described in a project specific post-injection site care and site cl osure plan. EPA also believes that periodic reviews and updates, wh ere necessary, to the plan are important to ensuring that the site continues to be managed effectively and to determine whether shortening the monitoring timeframe is appropri ate. The post-injection site care requirements in the final GS

77rule incorporate a combination of a fixed time frame and a performance standard approach. The final GS rule offer owners or operators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe during the post-injection period based on si te-specific data, pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Cl ass VI well owner or operator to demonstrate, during the permitting process based on substantial da ta, that an alternative PISC timeframe may be appropriate if it ensures non-endangermen t of USDWs pursuant 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. 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 monitoring wells, perform post-injection monitorin g, demonstrate the appropr iateness of an alternative post-injection site care time frame, demonstrate non-endangerment, and perform site closure activities. The guidance will be available at http://water.epa.gov/t ype/groundwater/uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 24209 Letter Lines: 1615 to 1622

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

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

Comment Code: 5260 2.8.2.3 Adjusting the post-injecti on timeframe (seeking comment)

Comment: Rule Provision: 146.93(b)(4)

API Comments: (4) If such a demonstra tion cannot be made (i.e., if the carbon dioxide plume and press ure front have not st abilized) after the 50

- year period, the owner or operator must submit to th e Director a plan to continue post

injection site care.

Rationale: No longer necessary given changes above.

Individual Response: As described above, EPA believes that to ensure USDW protection from endangerment, a default timeframe for post-injecti on site care is necessary in most cases. A 50- year post-injection site care ti meframe represents a reasonable and protective monitoring period for most GS projects based on a review of re search studies, industry reports, and existing environmental programs, and evaluation of pub lic comments. However, EPA recognizes that

78alternative timeframes may be appropriate under limited, specific circumstances. For this reason, the Class VI rule offers owners or operators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretio n to shorten or lengthen the PISC timeframe during the PISC period based on site-specific data , pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Cl ass VI well owner or operator to demonstrate, based on substantial data during the permitting pro cess, that an alternative PISC timeframe may be appropriate if it ensures non-endangermen t of USDWs pursuant to requirements at §146.93(c).

Letter ID: 0170 Comment ID: 24210 Letter Lines: 1624 to 1641

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

Comment Code: 4730 2.7.3 Reporting associated with closur e and post-injection site care

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93)

Comment: Rule Provision: 146.93(e)

API Comments: (e) Once the Director has authorizeSd site closure, the owner or operator must submit a site clos ure report within 90 days that must

thereafter be retained at a lo cation designated by the Director. AFTER

COMPLETION OF ALL CLOSURE OPERATI ONS. The report must include:

(1) Documentation of appropriate inj ection and monitoring well plugging as specified in §146.92 and paragraph (c) of this section. The owner or operator must provide a copy of a survey plat which has been submitted to the local zoning authority designated by the Director. The plat mu st indicate the location of the injection well(S) relative to perm anently surveyed benchmarks. The owner or operator must also submit a copy of the plat to the Regional Administrator of the appropriate EPA Regional Office;

Rationale: Once the site closure report is submitted to the Director, the operator cease to bear responsibility for any further record retention. At this point, EPA becomes the steward of information for the project.

Individual Response: EPA disagrees that the owner or opera tor should not be responsible for record retention such as site closure reports. EPA believes that the requirements that the owner or operator retain, for ten years following site clos ure, records collected during the post-injection site care period at §146.93(f) and §146.93(h) are a ppropriate for the post-injection and site closure period to ensure that data are availabl e to support non-endangerment demonstrations and to address any concerns that may arise following site closure. This data will also support EPA's review of project data as part of the adaptive rulemaking approach.

Letter ID: 0170 Comment ID: 24211 Letter Lines: 1643 to 1659

79Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5800 2.13 Comments on emergency and re medial response (40 CFR 146.94)

Comment: Rule Provision: 146.94(b)

API Comments: (b) If the owner or operator obtains evidence that the injected carbon dioxide stream, DISPLACED FORMATION FLUIDS OR and associated pressure front may cause an endangerment to ENDANGERS a USDW, the owner or operator

must: (1) Immediately cease injection IN A PR UDENT MANNER CONSIDERING

CIRCUMSTANCES. (2) Take all steps reasonably necessa ry to identify and characterize THE ENDANGERMENT POSED; (3) Notify the Director or the designa ted representative within 24 hours OF

BECOMING AWARE OF TH E ENDANGERMENT; and

Rationale: Technical clarifications.

There is a slight change that immediat ely ceasing injection could have adverse impacts on other aspects of the operation.

Individual Response: After consideration of comments, EPA has finalized the rule language in §146.94(b) as proposed. In the introductory section of §146.94(b), EPA clarifie s that the pressure front, as defined in §146.81, is a zone where the pr essure differential is sufficient to cause the movement of injected fluids or formation flui ds into a USDW. Therefor e, displaced formation fluids are implicitly included in the requirements for §146.94. EPA al so clarifies that owners or operators must take action when the CO2 stream or pressure front may cause endangerment. In order to prevent the endangerment of USDW s, as required under §1421 of the SDWA, EPA expects the owner or operator to act preemptiv ely and not wait until endangerment has occurred. This language is consistent w ith existing UIC requirements fo r other well classes and EPA’s authority under the SDWA.

Regarding changes to the language in §146.94(b)(1), EPA believes that it is implicit that owners or operators should take care not to damage the well when ceasing in jection. At §146.94(b)(2), EPA is maintaining the requirement to “characterize the release.” As currently written, the

situation should be characterized whether or not a USDW has actually been endangered, and

owners or operators are encourag ed to discuss with the Direct or whether actual endangerment has occurred. Concerning commenters’ suggestions for §146.94(b)(3), EPA clarifies that the 24 hours begins when the owner or operator obta ins evidence of possible endangerment. EPA believes the rule language is clear on this requirement.

Letter ID: 0170 Comment ID: 24212 Letter Lines: 1661 to 1668

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

Comment Code: 5800 2.13 Comments on emergency and re medial response (40 CFR 146.94)

80Comment: Rule Provision: 146.94(d)

API Comments: (d) The owner or operator must notify the Director prior to conducting any well workover IN RESPONSE TO ANY CASE OF

ENDANGERMENT.

Rationale: In critical situations, time spent obtaining approval could adversely affect the ability to conduct operations or increase the level of endangerment.

Individual Response: Since proposal, EPA has modified the final regulatory language at §146.94(d) to clarify what constitutes a workover to address a well failure (which invokes remedial actions) and what constitutes a mainte nance-type workover. For maintenance-type workovers (i.e., those that are scheduled in adva nce), the owner or operato r must notify and gain approval from the Director prior to beginning the workover. In th e final GS regulation, EPA has moved this requirement to the reporting requi rements at §146.91(d) to clarify its intent.

Regarding concerns that notifica tion could delay responses, EPA cl arifies that the GS rule, at §146.94(b), describes procedures owners or opera tors must take in emergency situations. Specifically, upon determining that there is a problem with the we ll that may endanger a USDW, the owner or operator must firs t cease injection, then take all steps reasonably necessary to identify and characterize any release, notif y the Director, and implement the approved emergency and remedial response plan, which ma y include a well workover. EPA believes that ceasing injection (which the ow ner or operator would do immediately and before notifying the Director) is the immediate action necessary to prevent or mitigate endangerment of USDWs.

Letter ID: 0170 Comment ID: 24213 Letter Lines: 1679 to 1684

Comment Code: 5610 2.11.1 Allowing partial primacy for Class VI wells (seeking comment)

Comment: EPA Preamble Question: 1. EPA seeks comm ent on any aspects of the ongoing State efforts to regulate the GS of CO2 and how these efforts might be used to better inform a final Federal rulemaking. EPA Notice 43497.

API Response: API supports the implementa tion of partial primacy for Class VI separately from other classes of wells.

Individual Response: EPA agrees with commenters that states should be allowed to obtain primacy for Class VI wells independently of other well classes, and will allow independent primacy for Class VI wells under §145.1(i) of th e final GS rule. Given the potential for CCS (encompassing capture, transportation, and geologic sequestration) to be an important part of a national priority to address clim ate change, EPA believes that provi ding states the flexibility to obtain primacy for Class VI wells independently of other well cla sses can help foster effective management of CCS. EPA believes that allowing independent Class VI primacy may encourage

81states to take responsibility for implementation of Class VI regulations and provide for a more comprehensive approach to managing CCS projects by promoting the integrat ion of GS activities

under SDWA into a broader framework for mana ging CCS. Furthermore, GS operations involve ancillary activities (e.g., pipeli ne operations, pore space ownership, land use rights, and surface access) for which states can call upon other authorit ies that exist at the state level (but outside UIC authority) to provide a more comp rehensive CCS management approach.

The Agency believes that it is important for stat es to use their unique e fficiencies to promote adoption of this burgeoning and important tec hnology, while assuring that USDWs are protected from endangerment through the UIC regulatory framework. EPA believe s that, due to the importance of implementing an effective, comprehensive, and seamless CCS program, States should be provided the flexibility to obtain primacy for Class VI only.

EPA also believes that allowing states to apply only for Class VI primacy will shorten the primacy approval process for states. EPA's willingness to accept independent primacy applications for Class VI wells represents a shift in its longstandi ng policy of discouraging "partial primacy." It is very important to note that this shift in policy allowing for Class VI primacy does not apply to any other well Cl ass under Section 1422. EPA will continue to discourage applications for pa rtial primacy for all other well types under Section 1422.

EPA clarifies that states should be able to obtain primacy for Cla ss VI wells independent of other well classes provided they devel op regulations that are at leas t as stringent as the minimum Federal requirements (e.g., permitting, inspec tion, operation, monitoring, and recordkeeping requirements) provided in the final GS rule. EPA believes that existing programs can adapt their expertise to the new requirements for Class VI wells and will be able to develop a primacy application for Class VI wells under section 1422 of SDWA and en sure that their GS programs integrate into national climate change priori ties and protect USDWs from endangerment.

Letter ID: 0170 Comment ID: 24214 Letter Lines: 1687 to 1700

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: EPA Preamble Question: 2. Injection of CO 2 for the purposes of enhanced oil and gas recovery (EOR/EGR), as long as any production is occurring, will continue to be permitted under the Class II program. EPA seeks comment on the merits of this approach since owners or operators of some Class II EOR/EGR wells may wish to use wells for the purposes of production and GS prior to the field being completely depleted. EPA Notice 43502.

API Response: API strongly supports the abse nce of an economic test for oil and gas reservoir "depletion." API contends th at EOR needs to be maintained under the current Class II program and supports EPA’s proposal that any storage that occurs under EOR continues to be handled under the Class II program. Additionally, API supports th e creation of a subclass under Class II (e.g "Class

82IIB") for storage operations in hydrocarbon formations after EOR activities. See API’s proposed section 146.25.

Individual Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas recovery should remain under the Cl ass II Program. EPA rec ognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS sites.

However, the Agency disagrees that wells inje cting CO2 for the primary purpose of long-term storage should be regulated under Class II requirements (e.g., th e Class IIB category suggested by the commenter). The Agency believes that th e nature and risks of CO2 injection for the primary purpose of long-term storage poses differe nt risks than injecti on for the primary purpose of ER, and therefore has develope d new Class VI regulations to address these unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is significantly greater than for ER operations. Reservoir pressure conditions will also be different, with Class VI injection operations involving large volumes of CO2 and likely having higher pressures within their storage formations than Class II ER projects.

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 purpos e is oil and gas production, to Class VI, where the primary purpose is long-term storage of large volumes of CO2. The gu idance describes the methods

available for the Director to evaluate cha nges in risk to USDWs from projects, and recommended approaches the Director may use to evaluate whether a project should be regulated within the Class II or Class VI UIC program. This guidance will be available on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_sequestrati on.cfm. For more information, please see the discussion on transiti on of Class II wells in the pr eamble to the final GS rule.

Letter ID: 0170 Comment ID: 24215 Letter Lines: 1702 to 1716

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

Comment: Rule Provisions: 146.81(c) EPA Preamble Question: 3. EPA seeks comm ent on the approach to grandfather construction requirements at the Director ’s discretion for existing Class I, Class II, and Class V wells seeking to c onvert to Class VI wells, and whether additional construction require ments would be necessary to prevent endangerment

to USDWs from the GS of CO2. EPA Notice 43502.

API Response: API supports this provisi on. Candidate Class I and Class V wells for grandfathering will have a demonstrat ed record of performance under their existing operations and MIT programs to demonstrate sound performance and adequacy of well integrity that can be used as a basis for conversion to the Class VI program.

For Class II wells, API proposes that th ey remain under the Class II program

83when transitioning from EOR to GS.

Individual Response: EPA agrees that many Class I, Cl ass II, and Class V experimental technology wells are designed and constructed to withstand exposure to CO2. The final GS rule provides for the construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director that the wells were en gineered and constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all other Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met fo llowing a determination under §146.81(c).

EPA disagrees that wells transitioning from ER to GS should be regulated as Class II wells. During and following this transitional phase, ma ny of the unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk profile , warranting the specific requirements in the final Class VI rule.

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 purpos e is oil and gas production, to Class VI, where the primary purpose is long-term storage of large volumes of CO2. The gu idance describes the methods available for the Director to determine changes 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/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 24216 Letter Lines: 1718 to 1725

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

Comment: Rule Provisions: 146.81(c) EPA Preamble Question: 4. Additionally, EPA seeks comment on how the grandfathering approach for existing wells may affect compliance with the other requirements in its proposal. EPA Notice 43502.

API Response: All components of the exis ting wells with a proven record of performance should be grandfathered unless there are specific USDW endangerment concerns identified by the Di rector. See Comment above.

84Individual Response: EPA agrees that many Class I, Cl ass II, and Class V experimental technology wells are designed and constructed to withstand exposure to CO2. The final GS rule provides for the construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director that the wells were en gineered and constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all ot her Class VI requirements (reporting, monitoring, mechanical integrity testing, etc.) must be met fo llowing a determination under §146.81(c).

EPA disagrees that other requirements should al so be grandfathered. Following re-permitting of the project as GS, many of the unique factors of GS sites (e.g ., increased reservoir pressures associated with large volumes of stored CO2 a nd the corrosivity of CO2 in the presence of water) will result in an increased risk profile, warra nting the specific requirements in the final GS rule. Therefore, following re-permitting as Class VI wells, these projects would be subject to the operational, MIT, monitoring, reporting, plugging, a nd post-injection site ca re and site closure requirements in the final GS rule. See the discus sion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on these requirements.

Letter ID: 0170 Comment ID: 24217 Letter Lines: 1727 to 1734

Comment Code: 4430 2.4.4.3.3 Injection into coal seams above USDWs (seeking comment)

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 EPA Preamble Question: 5. EPA is proposing to preclude the inje ction of CO2 for long-term storage into coal seams where they are above the lo wermost USDW. EPA requests comment on this propos ed prohibition. EPA Notice 43503.

API Response: API opposes this restric tion. Qualification of a formation for storage should be based on performan ce-based standards and site-specific

considerations.

Individual Response: The final GS rule does not categorica lly preclude or prohibit injection into any type of formation, including coal se ams. Instead, the requirements are designed to ensure protection of USDWs from endange rment through proper siting, well construction, operation, monitoring, and PISC at all sites selected for GS.

EPA recognizes that some types of formations, such as coal se ams and basalts, are typically shallow and above the lowermost USDW. EPA exp ects that most injection wells conducting GS in these shallow formations will be permitted as Class VI wells and such wells will be issued waivers, provided that their owners or operators can meet all of the requirements for an injection depth waiver at §146.95 and demonstr ate that such injection can be performed in a manner that protects USDWs, as long as appropriate protec tions are in place. The Class V experimental technology well classification may, in some instan ces, be an appropriate permitting alternative. This decision should be informed through a di scussion between the injection well owner or operator and the Director to determine the purpose and proper design of the well.

85For additional information on the waiver approa ch and aquifer exemptions for Class VI wells, please see the final rule and pr eamble, as well as EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0170 Comment ID: 24219 Letter Lines: 1752 to 1769

Comment Code: 1614 1.3.1.2 Impurities in captured CO 2; purity standards for CO2

Comment: Rule Provisions: 146.81(b), 146.81(d) EPA Preamble Question: 7. By defining "carbon dioxide stream" to exclude hazardous wastes (146.81(d)), EPA’s rule, if finalized, assures that it would apply only to CO2 streams th at are not hazardous wastes as defined in 40 CFR Part 261. As a result, EPA’s proposed ru le would preclude th e injection of hazardous wastes in Class VI injection we lls. EPA seeks comment on this approach

and other considerations associated with the presence of "impurities" in the CO2

stream. EPA Notice 43503.

API Response: API agrees with the concep t that Class VI wells should not be injecting hazardous wastes but is propos ing some modifications to EPA’s

definition of CO2 stream in the rule. Th e modifications reflect the fact that

the source of CO2 should not be a factor in the context of defining the CO2 stream. The rule applies to the inject ion of CO2 and should not address the origins of the materials since that is beyond the scope of this regulation. The original text would have precluded injection of CO2 from some sources. The question of how CO2 should be accounted fo r, and from what sources, in a GHG management and accounting system is beyond the scope of this regulation.

Individual Response: EPA agrees; the GS regulation applies to injection of CO 2 for the purpose of GS, regardless of the source of the CO2. It is beyond the scope of the GS rule and the UIC Program’s authority to require or set standards for upstream gene rators of CO2 or purification facilities. For purposes of GS, the UIC program ’s authority under the SDWA is limited to ensuring that GS projects are s ited, constructed, operated, and clos ed in a manner that protects USDWs. Although the GS regulation does not apply to the source of CO2 streams, the GS rule, at §146.82(a)(7)(iv), requires the owner or operator to submit data about the site, including an analysis of the chemical and physical char acteristics of the CO2 stream because the

concentrations of minor and tra ce elements in CO2 streams for GS projects are likely to vary by facility, coal composition, plant operating cond itions, and pollution removal technologies.

Letter ID: 0170 Comment ID: 24220 Letter Lines: 1771 to 1792

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment)

Comment: Rule Provisions: 73 FR 43504 EPA Preamble Question: 8. Class VI requirements and permits will need to be carefully structured to ensure that they do not "authori ze" inappropriate

86hazardous releases. This would include clarifying if there are potential releases from the well which are outside the scope of the Class VI permit. EPA requests comment on particular situations where this might occur. EPA notice

43504.

API Response: Well chosen sites should prevent these conditions from occurring. At the same time, permit writers should not write permits so restrictive as to make the undertaking of a GS project unten able. EPA should remember that CERCLA liability will not only impact owners and operators of GS projects, but also hundreds, thousands, and even more nume rous pore space owners. EPA should consider the threat of subjecting these pore space owners to CERCLA liability. Their property interests in the CO2 GS project injection zones could subject them to strict, joint, and several liab ility under CERCLA pursuant to whatever liability theories might be developed by future litiga nts seeking compensation for response and remediation costs incurre d in the cleanup of releases from geologic sequestration inj ection zones. EPA should r ecognize the si gnificant chilling effect CERCLA liability concerns will have on GS projects, and seize the opportunity in this rulema king to alleviate any CERCLA liability concerns to the greatest extent possible.

Individual Response: The Agency thanks the commenter for their comments regarding the scope and possible impacts of CERCLA liability on CCS activities, and comments related to the CERCLA exemption for federally-permitted releases. EPA notes that the GS rule is not promulgated under CERCLA, therefore the applicabil ity of that statute wi ll not be determined under the SDWA or the terms of the GS rule, but rather according to th e CERCLA statute itself and any implementing regulations that may appl y. To the extent the commenter is seeking interpretations of RCRA or CERCLA, such interpretations are beyond the scope of this rulemaking.

CO2 itself is not listed as a hazardous substan ce under CERCLA; however, the CO2 stream may contain a listed hazardous substance (such as mercury) or may mobilize substances in the subsurface that could react with ground water to produce listed hazardous substances (such as sulfuric acid). Whether such substances may result in CERCLA liability from a sequestration facility depends entirely on th e composition of the specific CO2 stream and the environmental media in which it is stored (e.g., soil or gr ound water). CERCLA exempts from liability, under CERCLA section 107, 42 U.S.C. 9607, certain "feder ally permitted releases" (FPR) as defined in CERCLA, 42 U.S.C. 9601(10). Class VI permits will need to be carefully structured to ensure that they prevent potential releases from the we ll which are outside the scope of the Class VI permit.

EPA agrees that proper site characterization that meets the requirements of §146.82 and §146.83 is important for protecting USDW s. Additionally, the UIC program Director has authority under SDWA §1423 to address potential compliance issues (e.g., potential releases that may endanger USDWs) resulting from injection violations in the unlikely even t that a remedial response is necessary. Although EPA anticipates that the need fo r emergency or remedial actions at GS sites will be rare, the GS rule requires, at §146.94, thatemergency and remedial response plans be

87developed and updated to address such events an d that owners or operators demonstrate that financial resources are set aside to imp lement the plans if necessary, per §146.85.

Regarding long term liability, once an owner or operator has met all regu latory requirements

under Part 146 for Class VI wells and the Dire ctor has approved site closure pursuant to requirements at §146.93, the owner or operato r will generally no longer be subject to enforcement for regulatory noncompliance. Furtherm ore, their financial instrument as required under §146.85 will be released if it was not used. However, even if a site closure is approved under §146.93, an owner or operator may be held liable for regulatory noncompliance (including violation of 40 CFR 144.12) in ce rtain circumstances. For example, an owner or operator may be held liable for regulatory noncompliance even afte r site closure was approved if the Director relied on erroneous information (e.g., erroneous modeling data) provid ed by the owner or operator when approving site closure.

Separate from EPA's authority to enforce regul atory compliance, an owner or operator may be subject to a §1431 response orde r even after proper site cl osure is approved under §146.93. Under §1431 the Administrator may require an ow ner or operator to take necessary response

measures if he or she receives information that a contaminant is present or is likely to enter a public water system or an USDW, which may pres ent an imminent and s ubstantial endangerment to the health of persons, and the appropriate Stat e and local authorities ha ve not acted to protect the health of such persons. Th e action may include issuing admi nistrative orders or commencing a civil action for appropriate relief against the ow ner or operator of a Class VI well. If the owner or operator fails to comply with the order, they may be subject to a civil penalty for each day in

which such violation occurs or failure to comply continues.

Furthermore, after site closure an owner or ope rator may remain liable under tort and other remedies, or under other federal statutes includi ng, but not limited to, Clean Air Act, 42 U.S.C. §§7401-7671; CERCLA, 42 U.S.C. §9601-9675; and RCRA, 42 U.S.C. §6901-6992. EPA does not have authority to transfer SD WA or other legal liability for Class VI wells to the State or federal government or a third-party fund. See the final rule preamble for further discussion of EPA's final approach.

EPA adds that promoting the use of GS is outsi de the scope of the GS rule. Rather, the purpose of the GS regulation is to ensu re that, where deployed, GS is c onducted in a manner that protects USDWs from endangerment.

Letter ID: 0170 Comment ID: 24221 Letter Lines: 1794 to 1803

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment)

Comment: Rule Provisions: 73 FR 43504 EPA Preamble Question: 9. EPA also reque sts comment on other considerations associated with the presence of impurities in the CO2 stream related to CERCLA.

EPA Notice 43504.

API Response: API is concerned that pot ential CERCLA liabilities will have the

88potential to chill enthusiasm for undertak ing GS projects. EPA needs to respond clearly and positively to this concern by developing appropriate language in the regulations and permits to provide the cl arity and assurance needed to promote

continued research and deve lopment for GS projects.

Individual Response: Again, EPA thanks the commenter for their comments regarding the scope and possible impacts of CERCLA liability on CCS activities. We reiterate that the GS rule is not promulgated under CERCLA , therefore the applicability of that statute will not be

determined under the SDWA or the terms of the GS rule, but rather according to the CERCLA statute itself and any implementing regulations th at may apply. To the extent the commenter is seeking interpretations of CERCLA, such in terpretations are beyond the scope of this rulemaking.

Letter ID: 0170 Comment ID: 24222 Letter Lines: 1805 to 1824

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones (seeking comment)

Comment: Rule Provisions: 73 FR 43506 EPA Preamble Question: 10. EPA’s proposal would provide the Director the discretion to require the owner or op erator to identify and characterize additional confining and containment zone s above the primary (i.e., lowermost) confining zone that could further impede vertical fluid movement and allow for pressure dissipation. EPA says that thes e layers could provide additional sites for monitoring, mitigation, and remediati on. EPA’s proposal w ould not require

that these additional zones be identified for all GS sites because their absence does not necessarily indicate inappropriateness of a GS site. However, if such zones are present, information about th eir characteristics can provide inputs for predictive models, identify appropri ate monitoring locations, and improve public confidence in and acceptance of a proposed GS site. EPA specifically seeks comment on the merits of requiring th e identification of these additional

zones. EPA Notice 43506.

API Response: API holds that secondary c ontainment is not mandatory. There are many areas where a single confining zone can be shown to be hi ghly protective of USDWs. Adequacy of containment must be done on a site-speci fic basis. This requirement would reduce the number of CCS storage site opp ortunities while increasing costs and not enhancing protection.

Individual Response: EPA clarifies that secondary confini ng zones are not required for all GS sites. Rather, secondary confini ng zones are required when the Di rector determines that these zones are needed to maximize the protection of USDWs from endangerment. EPA retains the requirement to identify additional containment/confining zones, if required by the Director, as proposed (e.g., §146.83(b)). EPA believes that, in some situations, the presence of additional confining and containment zones above the pr imary (i.e., lowermost) confining zone can improve USDW protection. These layers could fu rther impede vertical fluid movement and

89allow for pressure dissipation, and also provide additional sites for monitoring, mitigation, and remediation. EPA disagrees that the requirement would reduce the number of sites available for GS. The intent of this requirement is to ensure that a proposed site pr ovides adequate protection of USDWs from endangerment; if this protection cannot be demonstrated, the Director would not issue a permit for GS at the site.

Letter ID: 0170 Comment ID: 24223 Letter Lines: 1826 to 1846

Comment Code: 3330 2.2.1.3 Applicability /adequacy of computational models (seeking comment)

Comment: Rule Provisions: 146.82( c), 146.84, 146.90(d)(2) EPA Preamble Question: 11. EPA believes th at predicting the co mplex multi-phase buoyant flow of the CO2, "co-injectates," and compounds that may be mobilized due to injection requires the sophistic ation of computational models. EPA proposes that the owners or operators of GS wells be required to delineate the AoR for CO2 GS sites using computationa l fluid flow models designed for the specific site conditions and injection re gime. EPA seeks comment on the use of modeling for AoR delineation. EPA Notice 43506.

API Response: Modeling is well developed technology that can readily simulate complex behavior of injected CO2. It s hould be one of the techniques used to delineate the AoR. Modeling alone though should not be the sole basis for determining the AoR. Other technologies su ch as seismic, use of off-set wells,

should also be considered when delineating the proposed AoR.

The oil and gas industry has a great deal of experience that can be generally applied in the delineation of the AoR.

The most complex model is not always nece ssary to adequately delineate the AoR. Some CO2 EOR projects have successfu lly operated for decades using only production data and pressure mapping, wh ich has in effect defined AoR.

Individual Response: EPA agrees that the AoR should not be based exclusively on modeling. EPA has clarified the AoR modeling requirement in §146.84(c)(1) for the final rule. It now reads, “Predict, using existing site characte rization, monitoring a nd operational data, and computational modeling, the projected lateral and vertical migration of the carbon dioxide plume and formation fluids in the subsurface from the commencement of injection activities until the plume movement ceases, until pressure differentials sufficient to cause the movement of injected

fluids or formation fluids into a USDW are no longer present, or until the end of a fixed time period as determined by the Director.”

EPA clarifies that the model i nputs must include act ual geologic information, data collected during the site characterization process (e.g., information about artificial penetrations), and anticipated operating parameters (e.g., injection rates) submitted with the permit application under §146.82. This would include any seismic or off-set well data collected to meet the

90requirements of §146.82(a). Models will be revise d and recalibrated during subsequent AoR reevaluations, which must account for all availa ble monitoring and operational data, as required at §146.84(e).

Letter ID: 0170 Comment ID: 24224 Letter Lines: 1848 to 1862

Comment Code: 3350 2.2.1.5 Use of proprietary models for GS sites (seeking comment)

Comment: Rule Provisions: 146.84 EPA Preamble Question: 12. In some cases, ow ners or operators may choose to use proprietary models (i.e., not available for free to the general public). EPA says it is aware that the use of proprietary codes ma y prevent full evaluation of model results (e.g., NRC, 2007). Severa l popular codes in the petroleumreservoir engineering discipline are propr ietary and owners or operators of particular sites may prefer to use these c odes as they have previous experience with them, and they have been used in peer-reviewed studies to model CO2 sequestration. When using a proprietary model, owners or operators should clearly disclose the code assumptions, rele vant equations, and sc ientific basis. EPA seeks comment on allowing the use of pr oprietary models for GS sites. EPA

Notice 43507.

API Response: Use of proprietary models should be allowed. EP A’s Confidential Business Information requirements should a pply to any proprietary model used.

Individual Response: EPA agrees that some of the availa ble proprietary models may meet the needs for calculating the AoRs of GS sites. EPA will allow their use in meeting the requirements for the GS regulation, but clarifies that GS well operators using proprietary models are required to disclose, to the Director's sa tisfaction, the code assumptions, re levant equations, and scientific basis. EPA acknowledges that several proprietary models have been used by petroleum-reservoir engineering professionals as we ll as in peer-reviewed studies to model CO2 sequestration. EPA

adds that its Confidential Business Informati on requirements at 40 CFR 144.5 will apply to the use of proprietary models.

Letter ID: 0170 Comment ID: 24225 Letter Lines: 1864 to 1871

Comment Code: 3330 2.2.1.3 Applicability /adequacy of computational models (seeking comment)

Comment: Rule Provisions: 146.84 EPA Preamble Question: 13. EPA seeks comment on the applicability of computational fluid flow models for delin eating the AoR of GS sites. EPA Notice

43507.

API Response: While computational fluid fl ow models can inform the delineation

91of the AoR, modeling shouldn’ t be the sole criteria for determining AoR. (See Comment # above also.)

Individual Response: As described above, EPA agrees th at the AoR should not be based exclusively on modeling. EPA has clarified th e AoR modeling requirement in §146.84(c)(1) for the final rule, specifying that site characterizati on, monitoring, and operati onal data must be used along with modeling.

Letter ID: 0170 Comment ID: 24226 Letter Lines: 1873 to 1881

Comment Code: 3530 2.2.3.1 AoR reevaluation fre quency (seeking comment)

Comment: Rule Provisions: 146.84 EPA Preamble Question: 14. EPA seeks comm ent on requiring the reevaluation of the site AoR on a periodic basis, under what conditions the AoR should be reevaluated, and the appropriateness of a 10- year minimum fixed frequency for

AoR reevaluation. EPA Notice 43507.

API Response: Rather than a fixed ti me period, API recommends following a performance based approach that would be based on significant changes in injection parameters or an omalous monitoring results.

Individual Response: EPA believes that periodic AoR r eevaluation at a set frequency is necessary to ensure protecti on of USDWs from endangerment and address the uncertainties inherent in predictive modeling. Periodic Ao R reevaluations at §146.84( e) ensure that a deliberate effort is made to verify, based on m onitoring and operational da ta, that the CO2 plume is moving within the subsurface as predicted. EP A believes that less frequent reevaluations may not be sufficient to appropriately model plume a nd pressure front moveme nt, establish conditions for corrective action, and ensure prot ection of USDWs from endangerment.

EPA clarifies that if site m onitoring data agrees with the existing AoR delin eation, a model recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration

that the current AoR delineation is ad equate based on site monitoring data.

Letter ID: 0170 Comment ID: 24227 Letter Lines: 1883 to 1897

Comment Code: 3630 2.2.4.1 Comments in favor of allowing phased corrective action

Comment: Rule Provisions: 146.84(f) EPA Preamble Question: 15. EPA proposes to allow a phased appro ach to corrective action but says this may not be appropriat e in all situations; therefore EPA is proposing that the Director have the discretion to decide to allow this approach, based on the unders tanding of relevant geol ogic and site conditions. EPA invites public comment on the merits and frequency of reevaluation of the

92AoR as well as the phased corrective acti on approach for GS wells. EPA Notice

43508.

API Response: API supports the EPA propos al. The phased approach allows the sound economic execution of the project ov er time without enda ngering USDWs. This approach prevents an operator from the unnecessary expense of remediating wells in an area that ultimately may not be affected by the storage project. Frequency of reevaluation should be based on site performance as noted in the prior comment.

Individual Response: EPA acknowledges the commenter’s s upport of phased corrective action and agrees that phased corrective action may provide many benefits to a project including, but not limited to, spreading the burden of cost, avoi ding delays in project start-up, allowing for use of future, improved corrective act ion techniques, and addressing unanticipated changes in the movement of the CO2 plume or pressure front . EPA believes that the phased corrective action approach is appropriate for GS projects, and retained it at §146.84(b)(2)(iv) in the final GS regulation.

Regarding the comment that AoR reevaluation fre quency should be based on site performance, as described above, EPA believes that periodic AoR reevaluation at a set frequency of at least every five years is necessary to ensure protec tion of USDWs from endang erment and address the uncertainties inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure that a deliberate effort is made to verify, base d on monitoring and operational data, that the CO2 plume is moving within the subsurface as predicted.

Letter ID: 0170 Comment ID: 24229 Letter Lines: 1899 to 1909

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment)

Comment: Rule Provisions: 146.86(b) EPA Preamble Question: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set op posite a cemented interval. EPA Notice

43509.

API Response: Generally the surface casi ng is set below the lower USDW but it should be recognized that this is not a ppropriate in all geol ogic settings. In some areas USDWs can extend much greater depths than would be appropriate for setting of surface casing. Regulations should recognize these situations and allow a surface casing setting depth that may not fully cover the USDWs.

Individual Response: Section 146.86(b)(3) requires that th e long-string casing extend to the injection zone and be cemented by circulating ce ment to the surface in one or more stages. It does not, however, specify how cementing would be accomplished, and gives flexibility to the owner or operator to propose alternate methods to provide a sufficient amount of cement to meet

93the standard that USDWs are pr otected from endangerment, s ubject to the approval of the

Director. EPA notes that there ar e many potential ways to meet the requirement in deep wells, such as the use of staged cementing. See th e 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/we lls_sequestration.cfm.

EPA adds that cementing of deep wells has been performed successfully in the past, for example, by owners or operators of Class I hazardous and Cl ass I municipal waste disposal wells. Some of these wells, which must meet the same cemen ting requirements for long-string casing as Class VI wells, are up to 12,000 feet deep (EPA, 2001).

EPA also received comments from stakeholders representing states, a water association, and industry supporting this provisi on, saying that it provides, at a reasonable cost, corrosion protection of the casing; prevents undesirable migration of fluids be hind the casing; provides support to the casing; and provides multiple barriers against endangerment of USDWs.

EPA recognizes concerns regardi ng construction of Class VI wells where the lowermost USDW is very deep. To further address comments on d eep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells opera ting under injection depth waivers must comply with additional construction require ments to ensure that wells used to inject above or between USDWs are protective. See the discussion of the wa iver approach in the preamble to the final GS

rule for additional information.

Letter ID: 0170 Comment ID: 24232 Letter Lines: 1920 to 1934

Comment Code: 2064 1.5.3.2 Grandfathering construction of Class II wells (seeking comment)

Comment: Rule Provisions: 146.81(c) EPA Preamble Question: 17. EPA also seeks comment on how the proposed grandfathering provisions for existing we lls (construction requirements) may affect compliance with the above, proposed construction requirements. EPA Notice

43509.

API Response: Grandfathering should be handled on a case-by-case basis. The standard for grandfathering should be dem onstrated performance of the well at protecting USDWs. Because the act of inject ion would be the same for CO2 EOR and CO2 storage, Class II CO2 EOR wells should be deemed to meet the requirements of 146.86 and 146.87 upon notification. The purpos e of grandfathering is to recognize that some wells may not meet c onstruction requirements of Class VI wells, but the performance of Class II CO2 injection wells justifies their use as Class II CO2 Storage wells ("Class IIb ") or Class VI wells if EPA does not adopt a special subclass for stor age under the Class II program.

Individual Response: The final Class VI regulations re quire that any owner or operator

94injecting CO2 for the primary purpose of long term storage obtain a Class VI permit with some special consideration for the fact that they are transitioning from a well not originally designed to meet Class VI requirements. The Di rector has the authority to dete rmine at what point a Class VI permit is required for those projects that are transitioning from the primary purpose of EOR to long term storage of CO2. The fina l regulation provides a set of tec hnical factors for the Director to evaluate in making this determination, at §144.19. EPA believes that th is approach provides sufficient protection of USDWs when there is an increased risk to USDWs as compared to traditional Class II operations while allowing for site-specific flexibility.

EPA is developing guidance on transitioning perm its from Class II to Class VI. The guidance will assist Directors in evaluating whether an in jection project should be transitioned from Class II where the primary purpose is oi l 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 determine changes in risk to USDWs from projects, and how the Director may determine whether a project should be regulated within the Class II or Class VI UIC program. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

In response to the comment that GS wells shoul d be regulated as Class II wells, EPA believes that injection for the primary purpose of long term storage is sufficiently different from Class II ER operations and warrant s tailored requirements. For exampl e, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will also be different, with Class VI injection operations involving large volumes of CO2 and likely having higher pressure s within their storage formations than Class II ER projects, which may result in fluid movement that endangers a USDW.

Letter ID: 0170 Comment ID: 24233 Letter Lines: 1936 to 1944

Comment Code: 3840 2.3.2 Horizontal well drilling techniques (seeking comment)

Comment: Rule Provisions: 146.86 EPA Preamble Question: 18. EPA seeks comm ent on the merits of horizontal well drilling techniques for GS wells and th e applicability of well construction requirements discussed in th is proposal. EPA Notice 43509.

API Response: Drilling of directional a nd horizontal wells is an established technology that can significantly reduce surface impacts of a GS project and improve the injection rate of a well. The CO2 injection wells at In Salah, Sleipner, and many in Texas are horizont al or have horiz ontal sections.

Individual Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appr opriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, el ectric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously suppo rted the concept and provided many reasons why horizonta l wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that

95horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensu re the protection of USDW s from endangerment.

Letter ID: 0170 Comment ID: 24234 Letter Lines: 1946 to 1958

Comment Code: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking comment)

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment)

Comment: Rule Provisions: 146.86, 73 FR 43510 EPA Preamble Question: 19. EPA seeks comment regarding requirements for degradation-resistant well construction materials, such as acid-resistant

cements and corrosion resist ant casing. EPA Notice 43510.

API Response: The well should be looked at as a system such that not each individual component needs to be CO2 re sistant as long as th e entire system provides an effective barrier under the subsurface conditions. Industry experience with CO2 EOR strongly supports the use of conventional oil field tubing, casing, and cements. Industry expe rience over the past 35 years has led to the development of corrosion mitigation measures (e.g. plastic or epoxy lined tubing, use of corrosion inhibitors, and pr oper dehydration of CO2) that provide a high degree of protection and mitigate any corrosive effects of injected CO2.

Individual Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced reco very, and that this practice has led to the development of many corrosion mitigation measures that would be appropriate for the design of

Class VI wells.

EPA believes that the GS rule provides flexibil ity: it does not specify materials to be used; rather, it provides owners or operators with the fl exibility to choose, as long as the materials used in Class VI wells are compatible with fluids with which they may come into contact and meet or exceed standards developed for such materials by API or ASTM International, or comparable standards approved by the Director, as provided at §146.86(b)(1). However, EPA clarifies that each component of the well system must be de scribed by the owner or operator and will be evaluated by the Director and mu st meet the requirements of the GS rule. 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/gr oundwater/uic/wells_se questration.cfm.

Letter ID: 0170 Comment ID: 24235 Letter Lines: 1960 to 1969

Comment Code: 4130 2.4.1.3 Appropriateness of using fractur ing for well stimulation (seeking comment)

Comment: Rule Provisions: 146.88(a) EPA Preamble Question: 20. EPA is requesti ng comment on the extent and scope to

96which hydraulic fracturing should be allo wed during GS injection, and whether the use of fracturing for the purposes of well stimulation is appropriate. EPA

Notice 43511.

API Response: The use of fracturing for stimulation should be allowed provided that there is no damage to the confini ng unit that would result in endangerment of USDWs. There are computer simulators to predict fracture behavior so the impact on the confining z one can be anticipated.

Individual Response: EPA agrees that stimulation should be permitted in some situations and

the final rule allows the use of hydraulic fracturing at GS site s, where approved by the Director. Hydraulic fracturing is one of several stimulati on technologies available to improve wellbore and formation injectivity. EPA clarifies that fractur ing is permitted during stimulation, but not during injection. During injection, the injection pressu re must not exceed 90 percent of the fracture pressure, as specified in §146.88(a).

All stimulation, including hydraulic fracturing, must be approved by th e Director. Owners or operators must submit a proposed stimulation program as part of the permit application under §146.82(a)(9); the plan must demonstrate that any stimulation activities will not compromise the integrity of the confining zone. The Director wi ll evaluate the owner or operator's proposed stimulation plan in the context of all information about the site , and the owner or operator must perform stimulation only as approved. It is possi ble that computer simulations may support this

determination to the Director's satisfaction. EPA clarifies that all data submitted with the permit application, including modeling of the AoR, w ill inform the Director's decision on whether hydraulic fracturing is accep table at a GS site.

Letter ID: 0170 Comment ID: 24236 Letter Lines: 1971 to 1976

Comment Code: 4120 2.4.1.2 Allowing hydraulic fracturing during GS (seeking comment)

Comment: Rule Provisions: 73 FR 43511 EPA Preamble Question: 21. EPA is also re questing information to better qualify the use of fracturing for GS injection in specific geologic settings and rock formation lithologies. EPA Notice 43511.

API Response: See response to #20.

Individual Response: As described above, the final ru le allows fracturing only during stimulation. At §146.88(a), the rule language states that the injection pressure may not exceed 90 percent of the fracture pressure of the injection zone, except during stimulation.

Letter ID: 0170 Comment ID: 24237 Letter Lines: 1978 to 1999

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment)

97Comment: Rule Provisions: 146.88(e)EPA Preamble Question: 22. EPA seeks comment on the merits of requiring downhole shut-off valves in GS wells. EPA Notice 43511.

API Response: Over-pressure protecti on is best achieved by ensuring compatibility of the casing/tubing material design strength with the surface injection (compression) system. Down-hol e shut-in devices are not appropriate for this application. These devises are installed in the tubing string and are typically near the surface of the well. They’re intended to seal the tubing in the event of catastrophic failure of th e wellhead. These devises would provide little if any protection to USDWs. Is not practicable to install these devises deep within the well (e.g. shortly above th e packer). Additiona lly these devises create a restriction on running other to ols like logging tools in the well and therefore could limit an operators ab ility to do required monitoring and diagnostic work. Lastly, these devises re quire periodic testing and maintenance which could require either pulling the de vise by wireline or by pulling the entire tubing string depending on the type of devise installed. Either of these activities would be disruptive and costly to the overall project operations.

A more appropriate approach would be installation of landi ng nipples at appropriate points in the tubing string which would allow use of wireline retrievable plugs when needed.

Individual Response: As described above, the final rule, at §146.88(e)(2), requires that owners or operators of onshore Class VI wells insta ll automatic surface shut-off devices. The rule

affords Director's discretion to mandate au tomatic down-hole shut-off devices in onshore situations that may warrant their use. The ru le requires, at §146.88(e )(3), that owners or operators of offshore wells within State territo rial waters install au tomatic down-hole shut-off

systems.

Letter ID: 0170 Comment ID: 24238 Letter Lines: 2001 to 2019

Comment Code: 4410 2.4.4.3.1 Comments in favor of allowing injection above/between

USDWs in certain circumstances

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 EPA Preamble Question: 23. EPA is awar e that the proposed requirement of injecting CO2 below the lowermost USDW may preclude injection into certain targeted geologic formations, which ma y be storage sites currently under consideration for GS. As a result, the Agency is considering and requesting comment on alternative approaches that would allow injectio n between and/or above the lowermost USDW, and thus poten tially allow for more areas to be available for GS while preventing USDW endangerment. EPA Notice 43512.

API Response: Injection above the lowest USDW should be allowed but the operator

must demonstrate confinement above and be low the injection formation. Retaining

98the restriction would remove a significant number of vi able formations from consideration. Industry has shown that it can operate CO2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW below the injection zone. Moreover, unde r the proposed rule, there are other measures that would provide real assura nce of formation integrity and require operators to demonstrate that their proj ect will not endanger USDWs, making the lowermost USDW restriction unnecessary.

Individual Response: As described above, EPA acknowledges that there are limited circumstances where injection above the lowerm ost USDW can be performed in a manner that protects USDWs from endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 establishes a pr ocess by which owners or operato rs can seek a waiver of the Class VI injection depth requirements for inje ction into non-USDW form ations above and/or

between USDWs.

Letter ID: 0170 Comment ID: 24239 Letter Lines: 2021 to 2030

Comment Code: 4410 2.4.4.3.1 Comments in favor of allowing injection above/between

USDWs in certain circumstances

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 EPA Preamble Question: 24. EPA is solicit ing comment on whether CO2 injection should be allowed into an injection zone above the lowermost USDW, when the Director determines that geologic cond itions (e.g., thousands of feet of intervening formations between the inj ection zone and the overlying and/or underlying USDWs) exist that will prevent fluid movement into adjacent USDWs.

EPA Notice 43512.

API Response: See response to #23. CO2 inj ection zones should be selected based upon site specific evaluation of performance based criteria.

Individual Response: As described above, EPA acknowledges that there are limited circumstances where injection above the lowerm ost USDW can be performed in a manner that protects USDWs from endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 establishes a pr ocess by which owners or operato rs can seek a waiver of the Class VI injection depth requirements for inje ction into non-USDW form ations above and/or

between USDWs.

Letter ID: 0170 Comment ID: 24240 Letter Lines: 2032 to 2039

Comment Code: 4460 2.4.4.4.1 Comments in favor of allowing aquifer exemptions in certain

circumstances

Comment: Rule Provisions: 73 FR 43512

99EPA Preamble Question: 25. EPA is also requesting comments on whether aquifer exemptions should be allowed for the pur pose of Class VI injection, and under what conditions should such aquifer ex emptions be approved. EPA Notice 43512.

API Response: There should be no changes to the aquifer exemption requirements in the UIC program as they exist today. Each aquifer exemption should be considered on a case-specific basis.

Individual Response: EPA acknowledges that there are lim ited circumstances where aquifer exemptions for GS may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer exemptions for Class II EOR/ EGR wells transitioning to Class VI injection for GS pursuant to requirements at §§146.4 and 144.7( d). Class VI owners or operators granted expansions of existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that is, aquifer exemptions will only be granted for projects that are transitioning from Class II

EOR/EGR wells to Class VI.

The Agency clarifies that the aquifer exempti on requirements and the injection depth waiver requirements serve different purposes. Class VI owners or operators granted expansions of existing Class II EOR/EGR aquifer exemptions fo r GS projects must meet all of the tailored requirements for GS wells in the final GS ru le, including the requirements at §146.83 for site criteria. EPA believes that, in most cases, the inj ection depth waiver is a more appropriate option than aquifer exemptions for Class VI injection, and believes that aquifer exemption expansions for GS should be granted in limited circumstances.

EPA clarifies that all decisions regarding whethe r expansion of existing aquifer exemptions will

be at the Director's discretion and based on site -specific information. If an owner or operator applies for a Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above and/or between USDWs, the perm it applicant must also apply for a waiver of the injection depth requirements pursuant to §146 .95 to ensure that if a waiver is granted, USDWs above and below the injection z one are protected from endangerment.

This approach is designed to ensure that th e differences between traditional Class II EOR/EGR operations and Class VI operati ons are considered during the aquifer exemption application process and the Class VI permitting process. Thes e differences include the anticipated large CO2 injection volumes associated with GS, the buoyant and mobile nature of the injectate, and its corrosivity in the presence of water. The Agen cy believes that this process will encourage owners or operators and Directors to consider the use of alterna tive formations for GS, including non-USDW formations through the waiver process, prior to applying for or approving aquifer exemption expansions for Class II EOR/EGR wells transitioning to Clas s VI GS operations.

For additional information on aquifer exemptions for Class VI wells, please see the final rule and preamble, as well as EPA's responses to comments on the Notice of Da ta Availability and Request for Comment.

100Letter ID: 0170 Comment ID: 24241 Letter Lines: 2041 to 2052

Comment Code: 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth

Comment: Rule Provisions: 73 FR 43512 EPA Preamble Question: 26. EPA seeks comm ent on whether the Agency should set a minimum injection depth requirement for CO2 GS, rather than require that such injection take place below the lowermost USDW. EPA Notice 43512.

API Response: There should be no minimum de pth for injection of CO2. The primary consideration should be prot ection of USDWs. A requireme nt for a minimum depth suggests an intention by EPA to require injection of CO2 in a supercritical phase. Such a requirement is not appropr iate since there ma y be areas where injection of CO2 in other phases may be the only option. Again, site-specific evaluation and protection of USDWs should be the basis fo r determining depth of injection.

Individual Response: EPA agrees that it is not appropriate to set a mi nimum injection depth for GS projects or require that the CO2 be injected in a supercriti cal state. EPA believes that a determination of site-suitability for GS (i.e., th at subsurface formations will receive and confine injected CO2) should be made on a site-speci fic basis. The GS rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific information to the Director to

demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be contained within the injection formation, and th at USDWs will be protected from endangerment.

EPA acknowledges that there are limited circum stances where injectio n above the lowermost USDW can be performed in a manner that protec ts USDWs, as long as appropriate protections are in place. The final GS rule at §146.95 establis hes a process by which owners or operators can seek a waiver of the Class VI injection de pth requirements for in jection into non-USDW

formations above and/or between USDWs. The waiver approach requires the submission of extensive, site-specific information (in conjunc tion with the permit appl ication submission) to demonstrate that injection of CO2 into a non-US DW that is above or between USDWs can be done in a manner that is protective of USDWs. Th e requirements are designed to ensure that the owner or operator, the Director, and the Regional Administrator cons ider, on a site specific basis, the implications, benefits, and challenges associat ed with GS and ensuring water availability and USDW protection. For additional information on the waiver approach, please see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0170 Comment ID: 24242 Letter Lines: 2054 to 2064

Comment Code: 4490 2.4.5 Use of tracers and potential im pact on human health or ecosystems (seeking comment)

Comment: Rule Provisions: 73 FR 43513-15

101EPA Preamble Question: 27. EPA’s proposal allows Directors’ discretion on whether to require the use of tracers, and if so, what types of tracers. EPA

seeks comment on the use of tracers in CO2 GS operations, and any potential impact of tracers on human health or ecosy stems as they relate to USDWs. EPA

Notice 43513.

API Response: EPA should not mandate the use of tracers. The value of tracers has been questioned by many. Further research of their use needs to be conducted before any final language is approved. Modeling and monitoring are much more reliable techniques for tracking the plume of injected CO2.

Individual Response: EPA agrees that the use of tracers may not be appropriate at all GS sites, but should be available as an option. For this reason, EPA does not require the use of tracers at all GS sites; however, the Director has discretion to require their us e if he/she determines that the use of tracers could improve monitoring of the site and enhance USDW protection from endangerment. The rule will also allow their use if proposed by the owner or operator and approved by the Director.

EPA continues to follow new and ongoing research on the safety and efficacy of tracers. For example, studies at the Frio Brine Pilot Experi ment site (Dayton, TX) used various types of tracers, including perfluorocar bon tracers (PFTs), sulfur hexa fluoride, and the noble gases krypton, neon, and xenon. These studies (e.g., Phel ps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005) found that tracers can pr ovide useful CO2 monitoring information at injection wells at depth and at near-surface locations. At Frio, tr acers enabled quantification of CO2 plume behavior and provide d a technique for model validity testing (McCallum et al., 2005). EPA will continue to track re search related to tracer use.

EPA has been following new and ongoing research on the safety and efficacy of tracers, including their efficiency and cost-effectiveness. The Agency plans to, every six years, collect and review data on GS projects to determin e whether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Letter ID: 0170 Comment ID: 24243 Letter Lines: 2066 to 2081

Comment Code: 4520 2.5.1 Continuous internal mechani cal integrity monitoring (seeking comment)

Comment: Rule Provisions: 146.89(b) EPA Preamble Question: 28. EPA’s proposal wo uld require owners or operators of Class VI GS projects to monitor internal mechanical integrity of their injection wells by continuously monitoring injection pressure, flow rate, and injected volumes, as well as the annular pressure and fluid volume to assure that no anomalies occur that may indicate an in ternal leak. EPA requests comment on the practicability of this requirement. EPA Notice 43513.

102API Response: There is concern regarding what constitutes continuous monitoring. Industry agrees that regular monitoring of the parameters identified by EPA is appropriate. Our experience with CO2 EOR st rongly shows that daily monitoring of most of these parameters is adequate (e xceptions to this would be on a sitespecific basis). Recording should genera lly be done on a daily basis and reporting on a semiannually basis. As a guiding principle, the frequency of monitoring should be determined by the le vel of risk posed by the injection operation.

Individual Response: EPA believes that continuous pressure monitoring to demonstrate internal mechanical integrity of Class VI wells required under §146.89(b), instead of periodic testing, which is required for most other types of deep injection wells, is important given the potential corrosive impact of CO2 and impurities on well ma terials, the potential geomechanical impacts to well integrity due to CO2 phase changes, and the temperature and pressure effects associated with injecting supercritical CO2. EPA also believes that the technology for continuous monitoring is available and is currently in fair ly wide use. EPA anticipates that Class VI injection wells will be equipped with dedicated computer-based continuo us pressure monitoring devices (in concert with the shut-off systems required for GS wells), which typically take readings several times per second (i.e., more frequently than daily) and record them electronically in a computer system. 40 CFR 146.91( a)(2) requires that monthly averages of the continuous annulus monitoring be re ported on a semiannual basis.

At least one commenter indicated that the t echnology required for continuous monitoring is currently available and should not present an und ue cost burden. Continuous annulus monitoring

is also conducted at the commercial-scale carbon capture and geologic se questration operation at the In Salah, Algeria natural gas plant where more than 3 million tons of CO2 have been sequestered since 2004.

EPA acknowledges that additional data on GS is n eeded and is using an adaptive approach to regulating GS. The Agency plans to collect and re view data every six years on GS projects to determine whether the appropriate amount a nd types of information and appropriate documentation are being collected, and to determ ine if modifications to the requirements are appropriate or necessary.

Letter ID: 0170 Comment ID: 24244

Comment: Individual Response:

Letter ID: 0170 Comment ID: 24245 Letter Lines: 2083 to 2092

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment)

103Comment: Rule Provisions: 146,89(c), 146,90(e) EPA Preamble Question: 29. EPA seeks comm ent on the appropriate frequency of internal and external MITs for GS inj ection wells, the appropriate types of MITs, and how to optimize MIT methods for GS. EPA Notice 43514.

API Response: Timing for conducting MI Ts, should be based on risk and performance factors. Industry experience with CO2 EOR Class II program requires MITs every 5 years. This frequency has proven protective of USDWs. Given the

similarities between CO2 EOR wells and GS wells, API recommends 5-year frequency

in this case as well. The MIT should test integrity of the long string casing,

Individual Response: EPA disagrees that a five-year extern al MIT is appropriate. The final GS regulation retains the requirement that owners or operators of Class VI wells must demonstrate injection well external mechan ical integrity at least once annually under §146.89(c). While EPA acknowledges the successful history of the Class II injection program, the Agency believes that CO2 injection for GS is substantially different from Class II ER operations and believes annual MITs are justifiable for the pr otection of USDWs from endangerment given the unique nature of CO2 GS relative to other injecti on operations, including the potential corrosive impact of CO2 in the presence of water and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2 phase ch anges, the temperature and pre ssure effects associated with injecting supercritical CO2, and the buoyant natu re of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA chose a more cons ervative initial approach in the early stages of deployment for GS.

In addition, a comprehensive review conducte d by EPA of MIT results from 1993 to 1998 found that Class I wells injecting corrosi ve fluids fail MITs at rates two to three times higher than those that inject non-corrosive fluids (USEPA 1999). Given the potentia l for CO2 to be corrosive (e.g., in the presence of water or aqueous formation flui ds), there is a potential risk factor for MIT failure and, for this reason, EPA be lieves that the tailored MIT requi rements in the final GS rule are appropriate.

EPA adds that it is using an ad aptive approach to regulating GS. The Agency plans to collect and review data every six years on GS projects, including MIT da ta, to determine whether the appropriate amount and types of information a nd appropriate documentation are being collected,

and to determine if modifications to the requirements are appropriate or necessary.

Letter ID: 0170 Comment ID: 24246 Letter Lines: 2092 to 2098

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment)

Comment: in this case as well. The MIT should te st integrity of the long string casing, packer, and tubing and to the extent pract icable, should test the integrity of the cement isolating the injection zone . There are many methods for conducting MITs. EPA should allow operators adequa te flexibility in selecting the appropriate methods for their specif ic situation. API RP90 provides good

104examples of various methods for detecti ng mechanical failures, managing those risks, and conducting MITs.

Individual Response: EPA believes that the MITs describe d in the rule at §146.89 are effective methods and have been used successfully by injection well operators for decades and provide an important early warning of potential pr oblems in the injection well system.

EPA agrees with the commenter that flexibility to choose appropriate MITs is important, and the GS rule affords this flexibility by requiring th e owner or operator to prepare and gain approval for a project-specific testing and monito ring plan that incl udes MITs under §146.90. EPA clarifies that the regu lations allow the Director to requi re additional methods or, with the Administrator's approval, to approve the use of alternative MIT met hods based on specific information about the site or the well. See §146.89(e).

In addition, EPA is using an adaptive approach to regulating GS. The Ag ency plans to collect and review data every six years on GS projects to determine whether the appropriate amount and types of information and appropriate documenta tion are being collected, and to determine if modifications to the requirements are appropria te or necessary. For additional information, please see the discussion of MITs in the final rule preamble.

Letter ID: 0170 Comment ID: 24247 Letter Lines: 2100 to 2111

Comment Code: 4650 2.6.5 CO2 plume and pressure fr ont tracking (seeking comment)

Comment: Rule Provisions: 146.90 EPA Preamble Question: 30. EPA seeks comm ent on the requiremen t for monitoring of GS sites for the purpose of trackin g the location of the CO2 plume and associated pressure front over time. EPA Notice 43514

API Response: The frequency of monitoring should be dictated by site-specific operational and geologic conditions combined with the results of monitoring with model predictions. The guiding principle fo r monitoring is to verify proper confinement of the CO2 and ensure protec tion of USDWs. EPA s hould recognize that use of modeling and other monitoring t echniques are relativ ely qualitative processes that can have varying degrees of accuracy that will improve over time in an iterative process.

Individual Response: The GS rule stipulates that the monitoring frequency and spatial distribution of monitoring wells must be based on baseline geochemical data that were collected during the initial site characterization and the area of review evaluation (§146.90(d)(2)). The details of the geochemical monitoring will be based on site-specific information and described in the Director-approved testing and monitoring plan.

EPA adds that the iterative process of monitoring, mode ling, and AoR reevaluation is appropriate to verify that the CO2 plume and pressure front are moving through the subsurface

105as predicted, verify the accuracy of the de lineation model (or identif y needed changes), and refine testing and monitoring activities to ensu re that USDWs are protected from endangerment and that there would be adequate warning of potential problems at the site before any endangerment could occur.

Letter ID: 0170 Comment ID: 24248 Letter Lines: 2113 to 2122

Comment Code: 4640 2.6.4 Pressure fall-off testing (seeking comment)

Comment: Rule Provisions: 146.90(f) EPA Preamble Question: 31. EPA’s proposal wo uld require that owners or operators perform a pressure fall-off test at le ast once every five years. EPA seeks comment on the use and frequency of pressu re fall-off testing for GS wells. EPA

Notice 43515.

API Response: 31. We recommend that an init ial falloff test be conducted upon completion of the well prior to any operational injection and after the first year of operational injection. Following the first year, the frequency should be at the discretion of the Director but the frequency should be aligned w ith the reevaluation of the AoR.

Individual Response: EPA believes that a frequency of at least once every five years, as specified at §146.90(f), is an appropr iate interval for pressure fall- off testing (particularly given the suite of tests operators will perform on the well and the site). EPA clarifies that the Director may require more frequent pressure fall-off tests at a specific proj ect, if necessary based on sitespecific circumstances. Pressure fall-off tests ma y be conducted in conjunction with other well performance tests (i.e., mechanical integrity testing) to ensure sa fe and effective operations. All monitoring data collected, including information from pressure fall-off tests, will be incorporated

in AoR reevaluations conducted at least every five years.

Letter ID: 0170 Comment ID: 24249 Letter Lines: 2124 to 2143

Comment Code: 4650 2.6.5 CO2 plume and pressure fr ont tracking (seeking comment)

Comment Code: 4655 2.6.5.1 Plume tracking techniques/ geophysical methods (seeking comment)

Comment: Rule Provisions: 146.90(g) EPA Preamble Question: 32. Based on inform ation evaluated to date, EPA believes that tracking the plume and pressure front is an impor tant companion step to address any uncertainties associated w ith initial AoR modeling and requests comment on this approach and more efficien t alternatives that may be used to track the plume and pressure front. EPA Notice 43516.

API Response: Based on experience to date, CO2 plume can be monitored using surface or wellbore seismic and possibly some remote satellite techniques. Monitoring of the pressure fr ont will be more difficult since that requires data

106from the injection formation that can onl y be obtained by drilling a well (which introduces additional artificial penetra tions into the containment system). Modeling can estimate the movement of a pressure front. Those estimations are limited by the accuracy of the model and its iterative adjustments as previously

mentioned.

EPA should note that plume and pressure fr ont are different concepts and should not be confused. They yield information on two different metrics. One tells you about the remaining capacity of the stor age formation and the other describes the direction and movement of the CO2 plume.

Individual Response: EPA believes that direct pressure me asurements are appropriate and that direct pressure monitoring will be feasible at all GS sites. The final rule (at §146.90(g)) requires owners or operators to perform monitoring to tr ack the extent of the CO2 plume and pressure front. The owner or operator must use direct me thods to monitor for pressure changes in the injection zone. Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys

and/or down-hole CO2 detection to ols) are also required unless the Director determines, based on site-specific geology, that such methods are not appropriate.

EPA believes that pressure monitoring in th e injection zone is n ecessary to track the development and movement of the pressure front and CO2 plume. Monitoring can also identify needed remedial actions, provide inputs for AoR reevaluation m odeling, evaluate predictions of plume movement, and target additional geoche mical and surface monitoring needs. Knowledge of the location of the CO2 plume and the associated pressure front will assure the public that GS projects are proceeding according to plan, provide sufficient information to the owner or operator and Director, or allow for appr opriate actions to address any indication that USDWs may be endangered.

EPA agrees that geophysical (e.g., seismic) methods are useful for plume tracking at GS sites. Remote sensing methods (e.g., PSInSAR) may also pr ove to be useful. Such methods may be an important component of plume tracking at some GS sites. For this reas on, the final rule (at §146.90(g)) requires the use of i ndirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools) unl ess the Director determines, based on site-specific geology, that such methods are not appropriate.

EPA is developing guidance on testing and mon itoring to assist owne rs or operators and Directors in evaluating requirements under §146.90, which will include discussion of identifying the extent of the CO2 plume and pressure front . The guidance describes available technologies and recommended approaches for implementing a testing and monitoring plan, including preoperational geophysical logging and testing of injection wells, MI Ts, injection well testing during operation, groundwater qualit y monitoring, tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequestration.cfm. In addition, in January 2009, DOE published a best practices manual entitled "Monitoring, Verificat ion, and Accounting of

107CO2 Stored in Deep Geologic Formations" (DOE/NETL-311/081508); this manual is included in

the docket for the for the final GS rule.

Letter ID: 0170 Comment ID: 24250 Letter Lines: 2146 to 2161

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking comment)

Comment: EPA Preamble Question: 33. EPA seeks co mment on the appropriate amount and

types of monitoring that should be conducted at a GS site. Specifically, EPA seeks comment regarding the usefulness of indi rect geophysical monitoring and surface air and soil gas monitoring. In addition, EPA seeks commen t regarding the use of a Director-approved monitoring plan for GS sites. EPA Notice 43517.

API Response: Monitoring techniques and frequency should be determined on a site-specific basis. Select ion of monitoring types and frequency should balance the potential risks posed by the project w ith the cost of monitoring. Surface and soil gas monitoring does not add value to the protection of USDWs. Many of the surface and soil gas mon itoring techniques currently being evaluated lack the track record necessary for use in a regulatory compliance setting. Moreover, the potential for false-positives could undermine public confidence in GS technologies. EPA should defer on us ing surface and soil gas monitoring technologies until the DOE Regional Partnerships can demonstrate their

effectiveness.

Individual Response: As described above, EPA acknowledges that air and soil gas monitoring to ensure USDW protection is no t necessary at all GS sites and agrees that the decision to use surface monitoring and the selecti on of monitoring methods for th e purpose of USDW protection will be site-specific.

EPA acknowledges that air and so il gas monitoring are subject to variability and may not be suitable in all settings as a method to ensure USDW protection. However, EPA does not believe that this should entirely preclude their use. For example, if a leak to the surface is suspected, surface monitoring could provide vital informa tion on its location and magnitude to assist owners and operators in identifying what US DWs may have been impacted by a leak. EPA

clarifies that the various air and soil gas monitoring methods (e.g., chambers, eddy covariance, hyperspectral imaging) all have different capabilities that may prove us eful in specific GS projects (Miles et al., 2005; Pickles and C over, 2005; IPCC, 2005; Menzies et al., 2001). The occurrence of false positives will be reduced by comparing monitoring data to baseline data collected prior to injection or from a nearby area away from the GS project.

Letter ID: 0170 Comment ID: 24251 Letter Lines: 2163 to 2184

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment)

108Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking comment)

Comment: Rule Provisions: 146.90, 146.93(a), 146.94(a) EPA Preamble Question: 34. EPA is proposi ng that permit applic ations for GS sites include several plans not curr ently required under existing UIC regulations. These plans include a mon itoring and testing plan, an AoR and corrective action plan, and a post-injecti on site care and s ite closure plan. EPA seeks comment on the merits of requiring plans for monitoring, AoR, and Post-injection site care as part of a permit application. EPA Notice 43517.

API Response: The development of such plans is a good idea because it negates prescriptive regulation of the process. AP I is concerned that every modification of a plan may trigger a major permit modification. Although actual monitoring of injection formation is most effective, th ere is still the unintended consequence of penetrating the confining zone to ga in that data. The number of monitoring

wells should not be established in advan ce. It is unclear how monitoring well construction, operation, and closure will be regulated since these are not actual injection wells.

Timing of development of plans should be linked to the actual activity being addressed (i.e. staged). It should not be necessary to prepare and submit a site closure plan or the post-closure monitori ng plan at the start of the project, particularly considering that these ac tivities will not occur for many years after the project starts.

Individual Response: EPA agrees with commenters that developing and following testing and monitoring plans is an important pa rt of assuring that a GS projec t is operating properly and is crucial for the early detection of potential e ndangerment to USDWs. EPA expects that the number of monitoring wells needed will be determined based on site-specific information. EPA also agrees that periodic updates to the plan are appropriate. EP A clarifies that the final GS regulation includes a requirement th at the AoR be reevaluated at least every five years, and it specifies at §146.90(j) that the oper ator revise the testing and mon itoring plan to incorporate the

results of the most recent AoR reevaluati on and recent operational and monitoring data.

EPA believes that monitoring using wells in the injection zone, e.g., for pressure monitoring as required at §146.90(g)(1), can be safely performed if the wells are constructed to prevent flow between the injection zone a nd USDWs or other layers above the confining zone. Such construction technologies exist and have been us ed in the oil and gas industry for years. The testing and monitoring plan must describe how th e owner or operator plans to site and construct monitoring wells. EPA is developing guidan ce on well construction that will include recommendations for monitoring well constructi on. The guidance will be available on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_sequestration.cfm.

EPA clarifies that every revision to the testing and monitoring plan will not necessarily trigger a major permit modification. The existing regulat ion at 40 CFR 144.39(a) identifies causes for

109modification of permits that would invoke the pu blic notification procedures at 40 CFR 124. In the final rule, EPA added text to §144.39(a)(5) that permit modificat ions would be required if the

Director determines that a modification is nece ssary based on an AoR reevaluation, amendments to any of the project plans, or a review of the testing and monitoring results.

In addition, 40 CFR Part 144.41 identifies causes fo r minor modifications of permits (which do not require following the procedur es of Part 124). In the final rule, EPA added a subparagraph (h) to §144.41 that would include minor amendments (e.g., to clarify, correct , or update) to the testing and monitoring plan, plugg ing plan, post-injection site ca re and site closure plan, or emergency and remedial response plan for a GS well (i.e., amendments that are not included under 144.39(a)(5) and that do not require additional permit requirements).

EPA is developing guidance on testing and mon itoring to assist owne rs or operators and Directors in evaluating re quirements under §146.90. The guida nce can be found on EPA’s website at http://water.epa.gov/type/groundwater/u ic/wells_sequestration.cfm. In addition, in January 2009, DOE published a best practices ma nual entitled "Monitoring, Verification, and Accounting of CO2 Stored in Deep Geol ogic Formations" (DOE /NETL-311/081508); this

manual is included in the docket for the final GS rule. EPA notes that closure of monitoring wells should be addressed in the post-inj ection site care and site closure plan.

EPA also believes that it is appropriate to re quire owners and operators to submit all plans, including the injection well pluggin g and post-injection site care a nd site closure plans, at the time of permit application. EPA belie ves that the Director needs a satisfactory level of assurance that the owner or operator has pl anned for these events before injection commences and that the owner or operator has ensured that appropriate financial reso urces are available to fund all required activities, as required at §146.85. The final rule retains requirements for submitting these plans with the permit application at §146.82(a).

Letter ID: 0170 Comment ID: 24252 Letter Lines: 2186 to 2192

Comment Code: 4760 2.7.6 Proposed reporting frequency (seeking comment)

Comment: Rule Provisions: 146.91 EPA Preamble Question: 35. EPA seeks comm ent on the frequency of all proposed reporting requirements. EPA Notice 43517

API Response: Frequency should reflect the level of risk asso ciated with the activity. Semi-annual reporting is adequate. Reporting s hould be on a project basis as opposed to a well basi s consistent with 146.23(c).

Individual Response: EPA agrees and is retaining the requirement at §146.91(a) for semiannual reporting of monitoring and operational data . External mechanical integrity testing, which must be conducted annually, must be reported with in 30 days of the test. EPA clarifies that some monitoring frequencies (e.g., associated with gr ound water monitoring and plume tracking) will be established in the approved testing and monitoring plan, which will be incorporated as a condition of the Class VI permit. The frequency ofthese tests will be determined based on site110specific information. For additional information, pl ease see the final rule and the preamble for a discussion of EPA's final approach to recordkeeping and reporting.

EPA disagrees that reporting shoul d be on a project, rather than a per-well basis. EPA notes that operators who want to streamline their reporting schedules can negotiate with the permitting authority to establish a schedule that allows repo rting on all wells in a GS project at the same time; however, data for each well must be report ed separately and at least as frequently as required at §146.91.

Letter ID: 0170 Comment ID: 24253 Letter Lines: 2194 to 2204

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment)

Comment: Rule Provisions: 146.91(c) EPA Preamble Question: 36. EPA seeks comm ent on the requiremen t for electronic reporting in its proposed rule. EPA Notice 43518.

API Response: API strongly supports the concept of elect ronic reporting. Industry’s objections to pr ior proposals for electronic re porting have been with the scope and breadth of information (inc remental over written reports) that the Agency has previously proposed. Electron ic reporting equiva lent to existing written reports would be supported by API. Until these concerns related to electronic reporting are resolved, such re porting may be encouraged but should not be required.

Individual Response: EPA agrees and believes that electron ic formatting is the most appropriate format for submitting Class VI project informa tion to the Director, and requires this at §146.91(e). Based on comments received on the propos ed rule, the majority of Class VI well owners or operators will have the capability to report electronically.

EPA is developing guidance for states that describes the recordkeeping, reporting, and additional data management needs associated with GS act ivities and provides recommended guidelines on the types of data to be collected for tracki ng GS projects, reporti ng to EPA for compliance tracking, and transfer of data to EPA's GS data system. The recordkeeping and reporting guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 24254 Letter Lines: 2206 to 2216

Comment Code: 4750 2.7.5 Comments on the merit of a nnual reports (seeking comment)

Comment: Rule Provisions: 73 FR 43518 EPA Preamble Question: 37. In addition to the above recordk eeping and reporting requirements, EPA considered a requirement for owners or operators of GS sites to provide an annual report during the lifetime of the proj ect, including the

111post-injection period, regarding the GS operation. Although EPA has not included a requirement for this report in its pr oposal, EPA seeks comment regarding the necessity for such an annual report. EPA Notice 43518.

API Response: An Annual report is not necessary given the other reporting requirements in the Rule. Alternatively, if this report was to replace the other reporting requirements, there woul d be value to the proposal.

Individual Response: The final GS regulation retains the reporting requirements as proposed, which does not include a requirement for an annu al report. Instead, EPA believes that periodic reevaluation of the AoR, as re quired at §146.84(e), along with any re visions to the required plans that may be necessary based on the AoR reevaluation, will promote an ongoing relationship between the permitting authority and the owner or operator. The final GS rule, at §§146.84(c), 146.90(j), and 146.94(d), requires owners or oper ators to review and update the AoR and corrective action plan, the testi ng and monitoring plan, and the emergency and remedial response plan throughout the life of the project. Owners or operators mu st review each plan and identify necessary amendments to the plan or demonstrat e to the Director that no amendment is needed. These reviews must be performed within one year of an AoR reevaluation, following any significant changes to the facility (e.g., the additi on of monitoring or injection wells), or when required by the Director. In no cas e can reviews occur less often than once every five years. See the final rule and preamble for further discus sion on EPA's final approach to reporting and recordkeeping.

While the Agency recognizes some concerns expressed by commenters about the burden associated with an annual report, the Agency 's decision to retain the semi-annual reporting requirement at §146.91(a) is because the semi-annua l report in conjunction with the continued dialogue associated with AoR r eevaluations and periodic updates to the plans is a preferred approach to an annual report.

EPA encourages and expects owners and operators to share monitoring a nd operating data with the public voluntarily, however (e.g., through the Internet). Provi ding the public with information throughout the GS project will help clear up and avoid public misperceptions about the nature and safety of GS.

Letter ID: 0170 Comment ID: 24255 Letter Lines: 2218 to 2239

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

Comment: Rule Provisions: 73 FR 43519-20, 146.93(b) EPA Preamble Question: 38. EPA is propos ing using a combination of fixed timeframe and a performance standard as described above. EPA is tentatively proposing a post-injection site care (monitoring) pe riod of 50 years with

Director’s discretion to cha nge that period to lengthen or shorten the 50 year period if appropriate. EPA requests comment on the proposed use of a tentative 50 year fixed timeframe that could be m odified at the Dir ector’s discretion based on monitoring and modeling data. EPA Notice 43519.

112API Response: API strongly objects to th e use of a 50-year default monitoring period. EPA offers no rationale for this arbitrarily-selected period of 50 years. Establishing a fixed and unusua lly long time period may create a significant barrier for operators cons idering entry into CCS operations. Criteria for determining the period for post-injection site care should be

Performance-based and a function of the site specific characteristics of a project such as project size, geologic factors, and rela tive risk of the project. (API offers such criter ia in our edits to §146.93(b)(3).)

Clear guidelines also need to be establis hed regarding when operators have met the performance standards that determ ine site closure. Specifically, the standard that the project no longer poses an endangerment to USDWs needs to be defined using reasonable risk-based criteria.

Individual Response: EPA disagrees that the post-injectio n monitoring period is arbitrary. In determining the post-injection s ite care-timeframe for the prop osed regulation, EPA reviewed industry reports, existing envir onmental programs, and initial GS research studies. EPA provided a synthesis of pertinent results from GS m odeling studies in the preamble to the proposed regulation. Further explanation of this analys is was included in an EPA-prepared background

document that is available in the federal docke t, titled "Computational Modeling of Underground Injection of Carbon Dioxide for Determinati on of Area-of-Review and Potential Risk to Underground Sources of Drinking Water." Based on review of these studies, modeling results indicate that the CO2 plume st abilization may occur on the time frame of 10-100 years after the cessation of injection. EPA believes that a 50-year default post-injection s ite care timeframe is a reasonable midpoint for most GS projects and available data, including data submitted by commenters, do not support a different default ti meframe, and has retained this in the final regulation. However, EPA recognizes that there may be site s where the 50 year post injection site care timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. For this reason, the GS rule o ffers owners or operators flexibility regarding

the duration of the PISC timefra me by: (1) allowing the Direct or discretion to shorten or lengthen the PISC timeframe during the post-in jection period based on site-specific data, pursuant to requirements at §146.93(b) ; or (2) affording the Director discretion to allow a Class VI well owner or operator to demonstrate, during the permitting process based on substantial data, that an alternative PISC timeframe may be appropriate if it ensu res non-endangerment of USDWs pursuant 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.

113EPA 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 required under 146.92 and 146.93. The guidance describes recommended approaches for how an owner or operator could plug injection and monitoring wells, perform post-injection monitoring, demonstr ate the appropriateness ofan alternative postinjection site care time frame, demonstrate non-endangerment, and perform site closure activities. This guidance will be available at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

Letter ID: 0170 Comment ID: 24256 Letter Lines: 2241 to 2247

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93)

Comment: Rule Provisions: 146.93 EPA Preamble Question: 39. EPA is re questing comments on the proposed requirements for well plugging, post-injecti on site care, and site closure, including the proposed requirements for the post-injection time period. EPA

Notice 43520.

API Response: See question 38 above re garding post closure time periods.

Individual Response: As described above, EPA acknowledges that there will be circumstances

where it can be demonstrated in less than 50 years that the plum e and pressure front no longer pose a risk of endangerment to USDWs. For th is reason, the final GS regulation includes a provision that the Director ma y, at his/her discretion, shorte n the post-injec tion site care timeframe if the owner or operator can demonstrat e that the GS project does not pose a risk to USDWs, as specified in §146.93(b)(2). Such a dem onstration will be site-specific, and based on pressure monitoring and USDW impacts. Alterna tively, the final rule at §146.93(c), also allows the Director to approve an alternative post-in jection site care timeframe where an owner or operator can demonstrate during the permitting proce ss that an alternative post-injection site care timeframe, other than the 50 year default, is appropriate and ensu res non-endangerment of

USDWs. The demonstration must be based on site -specific information, in cluding the results of site-specific computational modeling; the predicte d timeframe for pressure decline; the predicted rate of carbon dioxide plume migration; site-s pecific chemical processes that will result in carbon dioxide trapping; the predic ted rate of carbon dioxide trap ping; characteri zation of the confining zone(s); laboratory analyses or stud ies to verify the information on trapping; the presence of potential conduits for fluid move ment and the quality of abandoned well plugs within the AoR; the distance be tween the injection zone and th e USDWs above and/or below the injection zone; and any additi onal site-specific factors dete rmined by the Director. The

demonstration must meet the cr iteria at §146.93(c)(2) for ensuring the quality and accuracy of

the data and models on which the demonstrat ion is based. This demonstration would be submitted as part of the permit application, per §146.82(a)(18), in addition to the PISC and site closure plan require d at §146.82(a)(17).

114EPA 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 required u nder §146.92 and §146.93. The guidance describes recommended approaches for how an owner or operator could plug injection and monitoring wells, perform post-injection monitoring, demonstr ate the appropriateness ofan alternative postinjection site care time frame, demonstrate non-endangerment, and perform site closure activities. This guidance will be available at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

Letter ID: 0170 Comment ID: 24257 Letter Lines: 2249 to 2255

Comment Code: 5260 2.8.2.3 Adjusting the post-injecti on timeframe (seeking comment)

Comment: Rule Provisions: 146.93(b)(2) EPA Preamble Question: 40. In additi on, EPA seeks comment on whether the

Director should be allowed to shorte n the timeframe based on performance information, and whether EPA should require a shorter or longer post injection period if data suggests the time fram e should be adjusted. EPA Notice 43520.

API Response: See question 38 above re garding post closure time periods.

Individual Response: As described above, EPA recognizes that there may be sites where the 50 year post injection site care ti meframe may be either not appropr iate or more burdensome than necessary based on site-specific conditions. For this reason, the GS rule offers owners or operators flexibility regarding th e duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthe n the PISC timeframe during th e post-injection period based on site-specific data, pursuant to requirements at §146.93(b); or (2) a ffording the Director discretion to allow a Class VI well owner or operator to demonstrate, during the permitting process based on substantial data, that an alternative PISC timeframe may be appropr iate if it ensures nonendangerment of USDWs pursuant 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

115sites 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 required under 146.92 and 146.93. The guidance describes recommended approaches for how an owner or operator could plug injection and monitoring wells, perform post-injection monitoring, demonstr ate the appropriateness ofan alternative postinjection site care time frame, demonstrate non-endangerment, and perform site closure activities. This guidance will be available at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 24258 Letter Lines: 2257 to 2270

Comment Code: 5430 2.9.1 Comments on proposed financia l responsibility requirements (40 CFR 146.85)

Comment: Rule Provisions: 144.36 EPA Preamble Question: 41. Current UIC guida nce describes trust funds as a form of financial assurance. The owner or ope rator may deposit funds into the trust fund in phases; that is, either over the term of the initial permit or over the remaining operating life of the injection well, as estimated in the well plugging plan, whichever period is shorter. Because of th e possibility that the owner or operator may face financial di stress prior to the trust being fully funded, EPA is considering a guidance appr oach that would recommend adopting a pay in period of three years for GS pr ojects, consistent with other similar programs in the Agency. EPA Notice 43521.

API Response: Industry should have a vari ety of options for meeting financial assurance based upon the companies’ disc retion. Options should include selfinsurance, insurance, surety bonds or ot her appropriate financial instruments.

Individual Response: EPA has clarified the financial responsibility requirements in the final GS rule, and has included at §146.85(a) a list of qualifying financial re sponsibility instruments that may be used to demonstrate compliance with th e financial responsibilit y provisions, including trust funds, surety bonds, letters of credit, insurance, self insura nce, escrow accounts, or any other instrument(s) provided the Director dete rmines that the operator's proposed financial responsibility demonstration is adequate to protect USDWs from endangerment.

EPA clarifies at §146.85(a)(6 ) that, prior to obtaining a Class VI permit, an owner or operator may demonstrate financial responsibility by using one or multiple qualifying financial instruments for specific GS activi ties, thereby realizing greater fl exibility and cost savings from this regulation. In the event that the owner or op erator combines more than one instrument for a

116specific GS activity (e.g., well plugg ing), such combination must be limited to instruments that are not based on financial strength or performan ce (i.e., self insurance or performance bond), for example trust funds, surety bonds guaranteeing pa yment into a trust fund, letters of credit, escrow account, and insurance. In this case, it is the combination of instruments, rather than the single instrument, which must provi de financial responsibility for an amount at least equal to the

current cost estimate.

Letter ID: 0170 Comment ID: 24259 Letter Lines: 2272 to 2283

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking comment)

Comment: Rule Provisions: 73 FR 43521 EPA Preamble Question: 42. Current UIC re gulations for Class I hazardous waste injection allow for the use of insurance for purposes of demons trating financial responsibility. However, insurance was not included as part of the guidance provided for Class II injection because th is insurance mechanism was and still is, rarely used for the purpose of de monstrating financia l assurance for injection wells. EPA is assessing whethe r to provide guidance on the use of insurance providers and, if so, whether to update eligibility requirements for

insurers for GS wells consistent with other current Federal agency practices.

EPA Notice 43521.

API Response: See response to 41

Individual Response: As described above, owners or opera tors may choose from a variety of financial instruments listed in §146.85(a) to m eet their financial responsibility obligations, provided the Director determines that the operator's proposed financial responsibility demonstration is adequate to protect USDWs from endangerment by demonstrating the ability to pay for each activity for which financial res ponsibility must be demonstrated, including corrective action on wells in the AoR, injecti on well plugging, PISC a nd site closure, and emergency and remedial response.

Letter ID: 0170 Comment ID: 24260 Letter Lines: 2285 to 2293

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking comment)

Comment: Rule Provisions: 73 FR 43522 EPA Preamble Question: 43. EPA is asse ssing whether a financial ratings threshold for all companies using a self- guarantee, similar to those used by other Federal agencies, is appropriate. Th e Agency also is considering what constitutes an appropriate financial ra ting threshold, and whether a financial rating greater than BBB or Baa (i.e., the current rating threshold established under the UIC regulations) is appropriate for GS wells. EPA Notice 43522.

117API Response: See response to 41

Individual Response: As described above, owners or opera tors may choose from a variety of financial instruments listed in §146.85(a) to m eet their financial responsibility obligations, provided the Director determines that the operator's proposed financial responsibility demonstration is adequate to protect USDWs from endangerment by demonstrating the ability to pay for each activity for which financial res ponsibility must be demonstrated, including corrective action on wells in the AoR, injecti on well plugging, PISC a nd site closure, and emergency and remedial response.

Letter ID: 0170 Comment ID: 24261 Letter Lines: 2295 to 2302

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking comment)

Comment: Rule Provisions: 146.85 EPA Preamble Question: 44. EPA is reque sting comments on whether financial responsibility mechanisms to be recommended in EPA gui dance should be adjusted in the manner described, whether additional instruments should be included, and whether other adjustments to the financia l responsibility mechanisms should be considered, all subject to EPA’s aut hority under the SDWA. EPA Notice 43522.

API Response: See response to 41

Individual Response: As described above, owners or opera tors may choose from a variety of financial instruments listed in §146.85(a) to m eet their financial responsibility obligations, provided the Director determines that the operator's proposed financial responsibility demonstration is adequate to protect USDWs from endangerment by demonstrating the ability to pay for each activity for which financial res ponsibility must be demonstrated, including corrective action on wells in the AoR, injecti on well plugging, PISC a nd site closure, and emergency and remedial response.

Letter ID: 0170 Comment ID: 24262 Letter Lines: 2304 to 2310

Comment Code: 5436 2.9.1.3 Allowing separate financial demonstrations for plugging and abandonment and post-injection si te care (seeking comment)

Comment: Rule Provisions: 73 FR 43522 EPA Preamble Question: 45. The Agency is also requesting co mment on allowing separate financial demonstrations to be submitted for the plugging of the injection well and for the post-injection site care requirements. EPA Notice

43522.

API Response: See response to 41

118Individual Response: As described above, owners and opera tors may choose from a variety of

financial instruments to meet their financial re sponsibility obligations under the rule, provided the Director determines that the operator's pr oposed financial responsib ility demonstration is adequate to protect USDWs from endangerment, which means the abili ty of the owner or operator to pay for each activity for which fina ncial responsibility must be demonstrated, including corrective acti on on wells in the AoR, injection we ll plugging, PISC and site closure, and emergency and remedial response throughout the life of the project. The final GS rule specifies at §146.85(a)(1) the permitted types of fi nancial responsibility instruments. See the final rule and preamble for further discussion of EP A's final approach to financial responsibility.

Letter ID: 0170 Comment ID: 24263 Letter Lines: 2312 to 2324

Comment Code: 5520 2.10.1 Appropriateness of existing p ublic participation requirements (Part 25 and Part 124) for GS (seeking comment)

Comment: Rule Provisions: 73 FR 43523 EPA Preamble Question: 46. EPA requests comment on adopting the existing requirements for public participation at 40 CFR Part 25 and 40 CFR Part 124 and whether additional requirements should be included to reflect the availability of new tools for disseminating and gather ing information. Such tools include cable networks, the Internet, and ot her new technology. EPA Notice 43523.

API Response: The current provisions in Parts 25 and 124 are sufficient to inform the public. Additional requirements should not be included.

Public participation should be consistent across progr ams. If EPA believes the public participation requirements should be expanded, it should be done in a holistic manner across programs.

Individual Response: EPA agrees that the existing UIC pub lic participation requirements as specified in 40 CFR 25 and 40 CFR 124 are appropria te for GS projects. In addition, because of the unique nature of GS projects, and the anticipa ted level of public intere st in GS projects, EPA encourages early public involvement in GS proj ects. Providing the public with accurate, projectspecific information in the early stages of each GS project can help clar ify project details and avoid public misperceptions about the nature and sa fety of GS projects, a nd will allow a potential GS owner or operator and the permitting agency to address the public's concerns before the permitting process is complete.

In response to the suggestion to apply additional public participa tion requirements to all injection well classes, EPA notes that this is beyond the scope of the GS rulemaking.

Letter ID: 0170 Comment ID: 24264 Letter Lines: 2326 to 2335

119Comment Code: 5560 2.10.3 Enhancing the public particip ation process (seeking comment)

Comment: Rule Provisions: 73 FR 43522-23 EPA Preamble Question: 47. EPA also reque sts comment on ways to enhance the public participation process, including engaging communities in the site characterization process as soon as ca ndidate locations are identified. EPA

Notice 43523.

API Response: API does not believe that the public participation process should

be extended to the site characterization stage of a GS project, particularly given that many sites might be characte rized in the process of winnowing down the portfolio of potential sites.

Individual Response: The Agency believes that public particip ation is an important part of the UIC permitting process and wants to ensure wi de access to decision-making processes and information on projects that may affect the pub lic. GS permitting authorities must follow the existing public participat ion requirements for UIC permits as specified in 40 CFR Part 124. Generally, these regulations require the Director to notify the public regarding the availability of the draft permit and allow him or her to requ ire a public hearing on the draft permit. EPA encourages operators and permitting agencies to begin involving the public by providing information as early in the process as possible. Such information exchange can affect how the local community and surrounding communities percei ve potential environmental, economic, or

health effects.

Furthermore, the Agency recognizes that the ini tial phases of site evalua tion and site selection may begin in advance of permit application s ubmission. The public may become aware of these activities and begin to have questions or conc erns about the pending project. For this reason, outreach and education—which are outside of, but complementary to, the public notification process—can help clarify project details and a void public misperceptions about the nature and safety of GS projects. This may also benef it the owner or operator by improving local acceptance

of the site.

Letter ID: 0170 Comment ID: 24265 Letter Lines: 2337 to 2349

Comment Code: 5600 2.11 Comments related to UIC Program primacy for Class VI wells

Comment: Rule Provisions: 73 FR 43523 EPA Preamble Question: 48. To gain au thority for Class VI wells, States, Territories, and Tribes will be required to show that their regulations are at least as stringent as, and may be more stringent than, the proposed minimum Federal requirements (e.g., inspection, operation, monito ring, and recordkeeping requirements that well owners or operator s must meet). Such Primacy States, Territories, and Tribes are authorized under Section 1422 of the SDWA. EPA

Notice 43523.

120API Response: States should be able to ga in primacy as long as they show that their regulations are at least as stri ngent as the proposed minimum Federal requirements. EPA should ensure that adequate funding is provided for the delegated program.

Individual Response: EPA acknowledges that there may be technical and administrative challenges including resource concerns , and will work closely with the states to assist them in resolving funding issues or acquiri ng the resources, personnel, and training needed to address the unique technical challenges associated with GS.

EPA clarifies that, in order for States, Tribes, or Territories to obtain primacy for Class VI wells (under Section 1422 of the SDWA) they must demons trate that they have requirements that are at least as stringent as the Federal Class VI requirements; have the authority to inspect and assess construction and operation of the we lls as well as have the necessary legal authorities to take administrative, civil and criminal enforcement actions required by the SDWA under §1423; impose criminal, civil, and administrative pena lties on owners and operators for non-compliance with regulatory requirements; and demonstrat e sufficient/appropriate technical capacity (e.g., personnel, infrastructure, and t echnical expertise) to implemen t their Class VI programs.

EPA will also incorporate Class VI wells into the UIC Program's grant allocation process. The

States/Tribes/Territories must also demonstrate th at they have adequate resources to implement the program through matching resources against those allocated by the UIC Program's grant allocation formula. Currently, primacy programs ar e required to meet a minimum of 25 percent matching requirement.

Letter ID: 0170 Comment ID: 24266 Letter Lines: 2351 to 2363

Comment Code: 5610 2.11.1 Allowing partial primacy for Class VI wells (seeking comment)

Comment: Rule Provisions: 73 FR 43523, 73 FR 43529 EPA Preamble Question: 49. There may be benefits to parsing out primacy for Class VI wells, however EPA has not made a decision on this. Allowing States, Territories, and Tribes to acquire primacy for only Class VI wells may encourage them to assume the responsibility of implementation and provide for a more comprehensive approach to managing CCS projects (e.g., capture, transportation, and geologic sequestration). EPA is seeki ng comment on the merits and possible disadvantages of allowing primacy approva l for Class VI wells independent of

other well classes. EPA Notice 43523.

API Response: API supports the implementa tion of partial primacy for Class VI separately from other classes of wells . The geologic variation across the country justifies partial primacy.

Individual Response: As described above, EPA agrees with commenters that states should be

121allowed to obtain primacy for Class VI wells inde pendently of other well classes, and will allow independent primacy for Class VI wells under §145.1(i) of the final GS rule.

Letter ID: 0170 Comment ID: 24267 Letter Lines: 2365 to 2373

Comment Code: 5700 2.12 Comments on the proposed durati on of Class VI permits (seeking comment)

Comment: Rule Provisions: 144.36(a) EPA Preamble Question: 50. EPA proposes th at Class VI injection well permits would be issued for the operating life of the GS project including the postinjection site care period. EPA seeks comm ent on the merits of this approach.

EPA Notice 43523.

API Response: A permit for the life of the project would ensure the continuity of operations. Shorter time periods woul d yield administrative burden without

commensurate benefits.

Individual Response: EPA agrees with commenters that Cl ass VI permits should be issued for the operating life of the GS proj ect. The final rule maintains the lifetime permit provision and clarifies that the permit extends through the post-injection si te care period (144.36(a)). EPA believes that the iterative process of developing and executing the various plans required of GS well operators under the final rule (e.g., for Ao R and corrective action, testing and monitoring, injection well plugging, pos t-injection site care, and emergency and remedial response) is tailored to the unique aspects of —and is more appropriate for– GS than establishing a finite permit duration (e.g., five years as suggested by so me commenters). EPA adds that the required reviews of the AoR and corrective action pla n, the testing and monitoring plan, and the emergency and remedial response plan throughout the life of the project are preferable to a periodic permit reapplication. The iterative process and subsequent plan reevaluations ensure that

time and resources are committed to the most cr itical aspects of the permit in preventing endangerment to USDWs. EPA notes that the final ru le also adds a requirement that the Director review each Class VI permit at least every five years.

Letter ID: 0170 Comment ID: 24268 Letter Lines: 2375 to 2391

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

Comment: Rule Provisions: 73 FR 43527 EPA Preamble Question: 51. The Agency assumes three monitoring wells per injection well for the purpose of estimati ng national costs; however, the Agency recognizes that operators and primacy agency Directors may choose more or fewer monitoring wells depending on project site characteristics. Because the monitoring wells and associated costs repr esent a significant component of the Cost Analysis, the Agency acknowledges that this factor may be significant in

122the overall uncertainty of the Cost Anal ysis. EPA requests comment on whether three monitoring wells per injection well is an appropriate costing assumption.

EPA Notice 43527.

API Response: It is difficult to select a realistic ratio since each site will

have its own characteristic s that would significantly affect the number of monitoring wells necessary.

The attached report prepared by ARI for API discusses the cost modeling in greater detail.

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 original 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. For additional information on EPA's final regulatory approach, including testing and monitoring requirements, please see the final rule and preamble.

Letter ID: 0170 Comment ID: 24269 Letter Lines: 2393 to 2402

Comment Code: 7700 4.7 Executive Order 13045: Child ren's Health Protection

Comment: Rule Provisions: 73 FR 43531 EPA Preamble Question: 52. The public is invited to submit comments or identify peer-reviewed studies and data that asse ss the effects of early life exposure to

123changes in drinking water quality that may be caused by geologic sequestration

of carbon dioxide. EPA Notice 43531.

API Response: API is not aware of anythi ng unique about CO2 injection or its potential impacts on drinking water quality that would not be addressed within the existing drinking water program. The data EPA has on developing drinking

water standards and MCLs can be used in this situation.

Individual Response: EPA is funding research related to the potential for USDW contamination associated with GS projects. In addition, the Agen cy is tracking external research that focuses on potential exceedances of drinking water standards, which were developed by EPA and take into account impacts on children's health.

In the August 31, 2009, Notice of Data Availabi lity (NODA) and Request for Comment (74 FR 44802), EPA published the results of a study in which Lawrence Berkeley National Laboratory (LBNL) evaluated the potential for GS to cause changes in ground water quality as a result of CO2 leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium (Birkholzer et al., 2008a). LBNL

estimated the amount of trace elements from na tive mineral species that could potentially be mobilized by the intrusion of CO 2 and the potential ground water con centrations that could result to determine the potential for drinking water standards to be exceeded. EPA has also examined potential methods for conducting treatment of wa ter affected by a CO2 leak; this study is presented in the final rulemaking docket.

EPA continues to fund research in this area. In December 2009, EPA's Office of Research and Development (ORD) awarded a Science to Achieve Results (STAR) grant to Clemson University to investigate the potential for GS to affect USDWs. This research will involve laboratory experiments and modeling simulations to invest igate the fate of dissolved CO2 in underground geologic formations and to determine possible ri sks associated with the dissolution of CO2 in underground aquifers. This STAR Grant is among six such grants awarded to major universities and institutions focusing on: "Integrated De sign, Modeling and Monitoring of Geologic Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water."

EPA clarifies that the purpose of the GS rule is to protec t USDWs from endangerment through permitting, siting, construction, operation, injection, a nd post-injection site care and site closure requirements that are tailored to address the unique nature of GS. The Class VI requirements, therefore, minimize health risk s to all populations, including ch ildren. The "Risk and Occurrence Document for the Geologic Sequestration Rule making," available in the rulemaking docket, presents a broad discussion of risks to human h ealth and the environment associated with GS, including those addressed under SDWA authority and those environmental and human health impacts that are beyond the scope of the SDWA.

As part of its adaptive rulemaking approac h, EPA plans to collect and review available information, such as the research described above, and data every six year s on early GS projects, including impacts to USDWs and dr inking water quality that may aff ect the health of children, to determine whether the appropriate amount and t ypes of information and documentation are being

124collected and to determine if modifications to the requirements are a ppropriate or necessary.

Letter ID: 0170 Comment ID: 24270 Letter Lines: 2444 to 2559

Comment Code: 6100 3.1 Comments on the cost estimates

Comment: In several significant areas, the assumpti ons for what is required to comply with the new requirements in the cost anal yses seem far less comprehensive than what appears to be described in the proposed regulations.

Preliminary interpretation of the requirements set fo rth in the proposed rule appear, in some these cases, to be much mo re comprehensive than that assumed to be performed as part of the cost analys es. Several examples are provided below:

Geologic Siting Requirements

The costs assumed to be associated with the process of geologi c site evaluation seems to be underestimated significantly relative to what the proposed GS rule requires. The rule contains over four pages worth of fairly detailed requirements for GS site selection an d approval, including the following for owners or operators to prepare and submit:

“ Maps and cross sections of the USDW s near the proposed injection well.

“ Demonstration that the injection zone is: (1) sufficiently porous to receive the CO2 without fracturing and (2) extens ive enough to receiv e the anticipated total volumes of injected CO2. For this demonstration, owners or operators need to submit geologic core data, outcrop data , seismic survey data, cross sections, well logs, and other data that demonstr ate the lateral extent and thickness, strength, capacity, porosity, and permeability of subsurface formations. They must demonstrate that the injection z one should be of a sufficient lateral extent that the CO2 can move a sufficient distance away from the well and still remain in the same zone, without displaci ng fluids into USDWs. His would require

that structural features of a potential injection zone reservoir, such as the lateral extent, dip, or the presence of "p inchouts" (i.e., thinni ng or tapering out) can affect storage potential, would need to be examined.

“ Data on the local geologic structure, in cluding information on the presence of any faults and fractures that transect the confining zone and a demonstration that they would not interfere with co ntainment. These data are to support

determinations about whether these feat ures, if present, could potentially

become conduits for movement of CO2 or other fluids to shallower layers, including USDWs.

“ Results of geomechanical studies of fault stability and rock stress,

125ductility, and strength.

“ Information on the seismic history of th e area and the presence and depth of seismic sources to assess the potentia l for injection-induced earthquakes. Information on insitu fluid pressures is required to assess the potential for the pressures associated w ith injection to reactivate faults or to determine appropriate operating requirements.

“ Demonstration of the application one or more of a variety of techniques to characterize the receiving zones and confin ing zones of proposed GS sites. For example, geologic core data, test wells, and well logs can help determine rock formations’ strength and extent. Seismic and electrical methods can be used to reveal subsurface features. Gravity anom alies indicate density variations at depth, and gravity surveys can be used to locate voids, such as cavities and abandoned mines. Numerous geophysical logging tools can determine formation porosity. Large scale, regional pressure te sts can also provide insight into the fluid flow field and the pr esence and properties of ma jor faults and fractures that may affect flow and transport of CO2 and displaced brines.

“ Demonstration of the maximum sustainabl e injection pressure s that will not cause unpermitted fluid movement, in order to assure that owners or operators not exceed an injection pressure that woul d initiate or propagate fractures in the confining zone. This should be base d on geomechanical studies of fault stability and rock stresses and stre ngth, along with an examination and interpretation of geological maps and cr oss sections, seismic and well surveys,

determination of local stre ss fields, and modeling,

“ Information on the geochemistry of forma tion fluids that can affect whether a site is suitable for GS; to include what CO2 may act as a solvent, mix with native fluids to form carbonic acid, lead to the potential lib eration of heavy

metals into the formation fluids or break down the rock matrix or precipitate minerals and plug pore spaces, therefore reducing permeability (IPCC, 2005). Studies of rock samples and review of geochemical data from monitoring wells would be needed to evaluate the impact of these effects. Owner s or operators are to submit geochemical data on a) the injec tion zone, b) the conf ining zones, c) containment zones above the confining zone s in which any potentially migrating CO2 could be trapped, d) all USDWs, and e) any other geologic zone or formation that is important to the pr oposed monitoring program.

According to the EPA cost analysis, the acquisition and interpretation of most

or all of that described above, along with the reporti ng of this information according to the specifications set forth in the proposal, would amount to about 3.5 person-months of effort, or abou t $90,000. Recent Advanced Resources’ experience on the DOE SECARB GS demonstr ation project indicat es, at least for this early project, costs are likely to be five to ten times or more than this for a small scale pilot project. Similar work Advanced Resources has done for

126the International Energy Agency Greenhouse Gas Program (IEA GHG) indicates that costs for site selection and project desi gn for a commercial scale project could range from $5 to $20 mi llion per site.[FN2]

[FN2: Advanced Resources International, Re mediation of Leakage from CO2 Storage Reservoirs, IEA/CON/04/ 108, Report prepared for the IEA Greenhouse Gas R&D Programme, January 17, 2007]

In particular, meeting many of the re quirements set forth in the proposed regulations for GS site selection will very likely require the drilling of stratigraphic and/or delineation wells. This will be especially true in deep saline aquifers. No costs associated with su ch wells appear to be considered in the EPA costs analyses for site selection (see discussion below).

Record Keeping and Reporting Requirements

EPA proposes that:

"...permit applications for GS sites include severa l plans not currently required under existing UIC regulations. These plans include a monitoring and testing plan, an AoR and corrective action plan, and a post-inje ction site care and site closure plan. The requirement for additional plans is intended to provide the Director the opportunity to assess proposed project operating procedures, and addresses GS requirements that are seen to be site-specific (e.g., what monitoring techniques will be used). In addition, these plans are intended to establish an ongoing dial ogue between the operator and the permitting authority which is more substantial than that required for other classes of injection wells."

In EPA’s costs analyses, it appears th at only costs associated with the incremental monitoring and tes ting plan were considered.

Individual Response: EPA clarifies that all cost estimates are incremental and presented as an annualized present value. Incremental values are presented to capture only those costs directly attributable to the GS Rule, which take into account the costs that would be incurred under regulations already in pl ace prior to GS rule promulgation (i .e., the baseline). Calculation of costs as an annualized present value is a typical economic costing methodology that accounts for the time preferences for expenditures (present va lue calculations) and allows for comparison of

costs across rules that are incurr ed on various timelines. These f actors result in the presentation

of costs that are much lower than th e non-discounted costs of the regulation.

EPA has considered each comment on the assumed hours needed to perform each task and in a few instances, such as performing reservoir si mulation modeling, has made upward adjustments. EPA also determined that in some cases multiple sites would be characterized before an owner would find a site that was a good candidate for a project. Therefore, EPA increased the site characterization costs by a factor of four for saline projects. Site characterization costs for ER

127projects were not increased, based on the a ssumption that ER sites would already have a significant amount of data availabl e to preselect those sites that have a better chance of meeting requirements.

For the final rule, the estimated total (non- incremental) non-discounted cost for site characterization for a pilot saline project is $1.3 million. In incremental terms, this nondiscounted estimate is $453,000, which translates to an annualized present value of $26,000. This approach (i.e., the development of cost es timates that are incremental changes in cost relative to the baseline), is c onsistent with EPA Guidelines for Preparing Economic Analyses (September 2000) and with other major rulemakings under SDWA.

EPA clarifies that it included cost s of delineation wells under the ca tegory of stratigraphic testing (catalogued as cost element A-7). As presented in the Appendix A of the Cost Analysis, EPA assumes that a stratigraphic test well with a depth of 9,350 feet will need to be drilled for a

commercial-scale saline reservoir.

Regarding the cost and burden associated with the plans required with the permit application (i.e., the plans for AoR and corrective action, m onitoring and testing, emergency and remedial response, injection well plugging, and post-injection site care and site closure), EPA clarifies that the burden for these plans has been addressed in the cost analysis for the final rule. EPA notes that the burden for permit applications under th e baseline (based on Class I nonhazardous well requirements) includes burden for completing basic monitoring and tes ting plans, corrective action plans, and well failure contingency pl ans, as required at 40 CFR 146.14(a). A well plugging plan is also required under the ba seline at §146.14(c). The incremental burden associated with writing these plans under the fina l rule is assumed to be negligible. Because postinjection site care and site closure plans are not required under the baseline, EPA added burden for such plans to section 5.4.7 of the cost analysis.

Burden incurred to obtain the additional informa tion needed to complete the more detailed plans now required under the final rule and to compile th is information into the plans is addressed in sections 5.4.3 (AoR and Correct ive Action) and 5.4.7 (Monitoring).

For additional information on the final costing ap proach, please see the final cost analysis and technology and cost document in the final rule docket.

Letter ID: 0170 Comment ID: 29190 Letter Lines: 1041 to 1115

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: Rule Provision: 146.87(a)(2)(i)

API Comments: (i) Resistivity, spontaneous potential, and caliper logs before the casing is installed; and

128Rationale: After a few wells are drilled in an area, these evaluations are frequently unnecessary and yield little new information. This is an example of

where Director discretio n may be appropriate.

Rule Provision: 146.87(a)(2)(ii)

API Comments: (ii) A Cement bond and variable density log, and a temperature log evaluation log(s) after the casing is set and cemented.

Rationale: Unusual to run these logs in a surface hole due to uniformity of shallow geology. This is an example of where Director discretion may be appropriate.

The proposed change provides more flexibil ity to select the appropriate log to demonstrate adequate cement bond.

Rule Provision: 146.87(a)(3)(i)

API Comments: Resistivity, spontaneous potential, porosity, ca liper, gamma ray, fracture finder logs and any other logs the Dire ctor requires BASED ON SITE

SPECIFIC CONDITIONS AND RISK-BASED FACT ORS for the given geology before the casing is installed; and

Rationale: It is acceptable to specify basic logging requirements, however, special logs should not be specified. Any other informa tion from the area should

be used instead.

Rule Provision: 146.87(a)(3)(ii)

API Comments: (ii) A Cement bond and variable density log, and a temperature log EVALUATION LOG(S) after the casing is set and cemented.

Rationale: The proposed change provides more flexibility to select the appropriate log to demonstrate adequate cement bond.

Rule Provision: 146.87(a)(4)

API Comments: (4) A series of tests TEST(S) designed to demonstrate the internal and external mechanical integrity of injection wells, which may

include: (i) A pressure test w ith liquid or gas; (ii) A tracer survey DIAGNOSTIC TOOLS such as oxygen-activation logging; (iii) A temperature or noise log; AND/OR (iv) A casing inspection log. if required by the Director; and

Rationale: Technical and grammatical corrections

129In (iv), "if required by th e Director" is unnecessary, as it is in subsection (a)

Rule Provision: 146.87(a)(5)

API Comments: (5) Any altern ative methods that provide equivalent or better information and that are required of and/or approved of by the Director.

Rationale: Same comment as above in (iv).

Rule Provision: 146.87(b)

API Comments: (b) The owner or operator must submit to the Director A REPORT

DESCRIBING whole cores or sidewall cores RE PRESENTATIVE of th e injection zone and confining system and formation fluid sa mples from the injection zone(s). The Director may accept DATA FROM cores AND FL UID SAMPLES from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and

that such cores DATA are representative of conditions at the well IN

THE WELLBORE. The Director may require the owner or operator to core other

formations in the borehole.

Rationale: The information required should be sufficient to properly describe the injection and confining zones.

Individual Response: EPA believes that all logs, surveys, and tests listed at §146.87(a) are necessary to verify information about the injec tion and confining zones an d ensure that the well is being drilled and cased as approved, and has me chanical integrity. This information is needed

to demonstrate that the well can be operated and tested in a ma nner that protects USDWs from endangerment. While the tests do provide information on some of the same items, each provides unique data that build on each other and allow fo r interpretations not possi ble with a single test.

EPA notes that the Director ha s the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information. EP A believes that logs and tests must be performed on each well drilled regardless of existing in formation about the area to account for the complexity of CO2 injection well construction and the buoyancy of CO2. Existing lithologic and geologic information may lack the details need ed for site-specific we ll design and the geology needed to support protection of USDWs from endangerment.

EPA clarifies at §146.87(a)(2 )(ii) and 146.87(a)(3)(ii) that owners or operators must perform a cement bond (i.e., cement evaluation) log after the casing is set and cemented.

Regarding the comment on §146.87(a)(4)(ii), EPA disa grees that allowing the use of unspecified "diagnostic tools" would provide the same amount of information as the requirement to perform a tracer survey. The track record for tracer surv eys in evaluating mechanical integrity has been proven over time. EPA clarifies that a tracer survey is one of the mechanical integrity tests that

130may be required by the Director or used by the owner or op erator. EPA agrees with the commenter about the wording of the casing insp ection log requirement and made the suggested change to improve clarity. In the final regula tion, §146.87(a)(iv) does not include the phrase, “if required by the Director.”

Regarding the comment on §146.87(b), EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator must take whole cores or sidewall cores of the injection zone and confin ing system and formation fluid samples from the injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that includes: well log analyses (inc luding well logs), core analys es, and formation fluid sample

information...."

Letter ID: 0170 Comment ID: 29200 Letter Lines: 1117 to 1177

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: Rule Provision: 146.87(c)

API Comments: (c) PRIOR TO INJECTION WELL OP ERATION, the owner or operator must

record PROVIDE REPRESENTATIVE INFORMATION ON the fluid FORMATION temperature, FORMATION FL UID pH and conductivity, and reservoir pressure and

the static fluid level of the injec tion zone(s).

Rationale: Technical corrections. Reservoir pressure and static fluid level are redundant parameters.

The phrase "representative information" pr events the operator from having to do

all tests in all wells.

Rule Provision: 146.87(d)

API Comments: (d) At a minimum, the owner or operator must determine or calculate the following information c oncerning 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 characteris tics of the formation fluids in the injection zone.

Rationale: With the exception of calculati ng fracture pressure, the requirements of this section appear red undant to other requirements of prior sections. The fracture pressure requirement has been a dded to section 146.87(e) below. (2) and

131(3) are too vague.

Rule Provision: 146.87(e)

API Comments: (e) (D) Upon completion but Prior to INJECTION WELL operation, the owner or operator must conduct the following tests to verify hydrogeologic characteristics of the injection zone: (1) A pump test; or (2) Injectivity tests.

ESTIMATE FRACTURE PRESSURES OF THE INJECTION AND CONFINING ZONES

AND INJECTIVITY

OF THE INJECTION ZONE. ESTIMATES SH OULD BE BASED ON REPRESENTATIVE

HYDROGEOLOGIC

AND GEOMECHANICAL CHARACTERISTIC S OF THE INJECTION ZONE.

Rationale: Allows the use of information such as leak off te sts conducted during the drilling operation.

The results of a pump test (pumping flui d from the well) have no relevance for an injection well.

Deletion of the injectivity test would a llow the use of non-destructive methods to calculate fracture pressure.

Rule Provision: 146.87(f)

API Comments: (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 UPON SPUDDING THE WELL and NOTIFY THE

DIRECTOR OF submit any changes to the schedule 30 days 48 HOURS prior to

the next scheduled test.

Rationale: The changes reflect the reali ties of flexible rig schedules and operations. In addition, they are fully consistent with current Class II requirements and practices which deal w ith these issues on a daily basis.

Individual Response: EPA disagrees that "reservoir pre ssure" and "static fluid level" measurements required in §146.87(c) are redundant parameters. Although the static fluid level is equal to the bottom hole pressure, this may not al ways be identical to the reservoir pressure. Additionally, measuring the static fluid level prov ides additional assurance that the reading is accurate (or, provides the needed information in cases where a good reading is not obtained). In addition, a static fluid level measurement provides information regarding the proximity to USDWs that need protection afforded to them.

EPA believes that the requirement to provide information on the in jection and confining zones in

132§146.87(d) is warranted, and that the rule provid es flexibility to account for the variety of geologic conditions that may be encountered at GS sites.

EPA clarifies that the owner or operator has the option of using pump tests or injectivity tests specified at §146.87(e) depending on which would provide the most valuable information based on site-specific conditions. Further, EPA disagree s that pump tests are irrelevant to determining injection zone properties. Depending on the ch aracteristics or depth of knowledge of the confining and injection zone formations, pump test s may be necessary to prove that no hydraulic connection exists between the injection zone a nd a USDW. Additionally, EPA disagrees that the wording at §146.87(d) would lead the owner or operator to empl oy destructive testing methods for determination of fracture pressure. The wording "determined or calculated" allows for calculations to be performed ba sed on non-destructive methods.

EPA disagrees that the 30-day notification requirement is unreasonable. Acknowledging the developing nature of CO2 GS, EP A believes that involvement by the permitting authority in each project will provide much n eeded field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of

notification will ensure the Direct or's ability to be involved.

Letter ID: 0170 Comment ID: 29257 Letter Lines: 1899 to 1903 ; 1911 to 1915

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

Comment: Rule Provisions: 146.86(b) EPA Preamble Question: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set op posite a cemented interval. EPA Notice

43509.

API opposes the requirement for cementing the long string casing back to surface. Cementing requirements should focu s on ensuring competent isolation and seal across the injection zone and conf ining zone(s). Sealing the annulus between the long string and surface casing co uld limit an operators ability to monitor for leakage or conduc t remedial operations.

Individual Response: As described above, EPA believes th at the requirements for long-string casing are appropriate and offer appropriate flex ibility. EPA does not believe that the cementing requirements at §146.86 would prevent monitorin g, operation, and remediation of GS wells. Cementing of deep wells has been performed succe ssfully in the past by ow ners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operati on, and remediation (EPA, 2001). S ee 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 constr uction of Class VI wells. This guidance

133will be available on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0170 Comment ID: 29258 Letter Lines: 1899 to 1903 ; 1917 to 1918

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment)

Comment: Rule Provisions: 146.86(b) EPA Preamble Question: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set op posite a cemented interval. EPA Notice

43509.

Regarding packer setting depth, the dire ctor should retain discretion for allowing variation from this requirement.

Individual Response: EPA clarifies that the rule does allo w some Director's discretion in approving the owners or operators proposed well construction pla n. The Director will evaluate the appropriateness of the propos ed construction based on site-s pecific information about the injection project. EPA believes th at the use of tubing and packer in accordance with §146.86(c) will offer the best multiple-barrier protection of USDWs from endangerment. 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: 0170 Comment ID: 29282 Letter Lines: 2561 to 2578

Comment Code: 6100 3.1 Comments on the cost estimates

Comment: Financial Responsibility Requirements

The proposed rule states:

"Today’s proposal would require that ow ners or operators demonstrate and maintain financial responsibility, and ha ve the resources for activities related to closing and remediating GS sites. EPA is proposing that the rule only specify a general duty to obtain financial res ponsibility acceptable to the Director, and will provide guidance to be developed at a later date that describes recommended types of financial mechanisms that owners or operators can use to meet this requirement."

Obviously, since these requirements are not specified in the rule, they were not explicitly and quantitativel y considered in the EPA cost. These costs will be a very important factor in deciding whether GS projects are pursued. At least some discussion of the uncertainty associated with these costs, and the potential implications associated with this un certainty on EPA’s conclusions, at a

134minimum, is warranted.

Individual Response: Both the proposed and final GS Rule included a requirement for a demonstration of financial responsibility. The cost for demonstrating financial responsibility is distinct from the cost associated with the low pr obability of site failur e and remediation of the site, which is included as a separate item and de fined as a low percentage of capital expenditures on an annual basis. EPA included in the cost analys is for proposal and for the final rule the unit cost for demonstration of financial responsibility, which consists of the labor hours necessary to compile the firm’s financial information and pr oject-related cost information to demonstrate financial capacity to address a problem, including the potential for complete failure and resulting

closure of the site.

For additional information on the final costing ap proach, please see the final cost analysis and technology and cost document in the final rule docket.

Letter ID: 0170 Comment ID: 29283 Letter Lines: 2580 to 2648

Comment Code: 6100 3.1 Comments on the cost estimates

Comment: Site characterization costs considered in the EPA cost analysis do not include any costs for delineation wells.

For any target formation for GS that has not been extensively characterized by a large number of wells (such as deep sa line aquifers, in contrast to the generally relatively well defined depleted oil and gas fields), some wells will most likely need to be drilled to better understand the geology at or very near where the injection will take place. In many target formations, the information required for proper site ch aracterization (cross secti ons, performing inter-well seismic, the acquisition of geochemi cal, geomechanical, and geophysical information, the relative location of th e target injection zone and USDWs, characterization of the confining system , etc.) will require drilling additional some wells. In fact, this could often involve dril ling several wells to understand both vertical and areal heterogene ity in the vicinity where injection will take place. EPA’s cost analysis a ppears to conclude that no well drilling will take place as part of the geologic characterization of the GS site.

Perhaps it is EPA’s assumption that th e monitoring wells assumed under their characterization of monitoring costs will serve that purpose. If that is the case, then that needs to be made clear.

Labor rate assumptions for engineers in the EPA cost analysis are much too low.

For most labor related activities assume d in the EPA cost analysis, it was assumed that tasks would be performed by either geologists or engineers. The geologist’s hourly labor rate was as sumed to be $106.21 per hour, while the engineer’s hourly labor rate was assumed to be $53.52 per hour. Assuming 2,080

135hours per year (including vacation), a nd a overhead markup ranging from 2.0 to 2.5, would result in a "representative" geologist’s salary of $88,000 to $111,000 per year, and a "representative" engineer’s salary of $44,000 to $56,000 per year.

The American Association of Petroleum Geologists (AAPG) pe rforms an annual salary survey of its members.[FN3] Based on this survey, if one assumes that the geologists performing the assignments have five years of experience or less, the assumed labor rates or geologists are reas onable. However, it is important to note that in the last 3 years, th ese salaries have risen by 35%.

[FN3: http://www.aapg.org/explo rer/salarysurvey.cfm]

Because of the similarities in the engi neering tasks associated with GS and those associated with developing and producing oil and gas, it would be reasonable to assume that most engineeri ng tasks associated w ith GS would be preformed by individuals trai ned as petroleum engineers. The EPA cost analyses assume that these would be performe d by geologic or mining engineers.

The Society of Petroleum Engineers also performs an annual survey of its members, the last one conducted in Sept ember 2007.[FN4] The re sult of this survey shows that the mean annual salary of petroleum engineers in the U.S. was nearly $134,000. The average annual salaries for petroleum engineers with 0-10 years of experience were a little over $92,000. Of the various types of petroleum engineering categories considered in the survey, reservoir engineers (the most likely types to be involved in GS site characterization, reservoir modeling, and monitoring type s of activities) where th e second highest paid category (behind finance /administration) , with average annual salaries for those 0-10 years of experience being a little less that $100,000.

[FN4: http://www.spe.org/spe-app/spe/ career/salary_survey/index.htm]

Based on this, it seems that the labor rate assumptions for engineers in the EPA cost analysis were much too low, perh aps by a factor of two or more. (The assumed labor rate for engineers in EPA’s cost analyses are somewhat low even for mining engineers with some experience .[FN5],[FN6]) Since a large number of tasks are assumed to be performed by engi neers in EPA’s assessment, this could have a substantial impact on their overal l cost impact characterization, perhaps on the order of about $60,000 per GS site.

[FN5: http://www.bls.gov/oco/oc os027.htm#projections_data] [FN6: http://www.payscale.com/researc h/US/Job=Mining_Engineer/Salary]

Individual Response: For the final rule cost analysis, EPA updated labor costs using survey

information from the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Engineers (SPE), resulting in an incr ease of 115% in the rate for engineers. EPA

136believes the updated labor rates are consistent with those in the field and re presentative of labor costs for GS projects.

Using industry survey data from AAPG and SPE as presented in th e cost analysis, EPA increased the estimated labor rates significantly from the BLS estimates used in the cost analysis for the proposed rule. The updated loaded hourly labor ra tes in the final rule cost analysis are $107.23 and $110.62 in 2008$ for engineering geologists a nd engineers, respectively. These correspond approximately to annual salaries of $ 139,400 and $143,800 and represent increases from the proposed rule analysis.

For additional information on the final costing ap proach, please see the final cost analysis and technology and cost document in the final rule docket.

Letter ID: 0170 Comment ID: 29284 Letter Lines: 2650 to 2738

Comment Code: 6100 3.1 Comments on the cost estimates

Comment: Injection well drilling cost assumptions in the EPA costs analysis are reasonable based on today’s conditions, but may not properly reflect recent increases in costs, as well as, importa ntly, the situation wh ere demand for well drilling services in the GS industry e xpands dramatically, perhaps increasing costs correspondingly.

The most expensive activity likely to be associated with GS will be the costs associated with drilling injection wells, along with associated wells required for monitoring and site characterization. EP A assumes that the costs associated with just drilling injec tion wells can range from $210 to $280 per foot for wells typically drilled to a depth of on the order of 9,000 feet. Including all costs associated with well drilling and co mpletion increases the range to from $280 to $320 per foot for a 9,000 foot well.

According to the latest drilling cost surv ey by the American Petroleum Institute (for 2006):[FN7]

“ The average costs of drilling and comple ting wells in the U.S. (not including sidetrack wells) was $378 per foot. The av erage well depth in the U.S. was 5,560

feet.

“ The average well cost for all onshore wells in the 7,500 to 10,000 foot depth category was $2,660,000. The average depth of wells in this category was 8,722 feet. This then equates to an av erage cost of about $305 per foot.

[FN7 American Petroleum Institute, 2006 Joint Association Survey on Drilling Costs, April 2008]

As another point of reference, Advan ced Resources has drilled a GS well

137associated with a demonstration project in Mississippi, and is in the process of developing an AFE for a new well. Based on this experience:

“ A recent well drilled to 14,500 feet cost a little over $3,200,000, or about $215 per foot.

“ The drilling and completion costs estimated for a planned new injection well to be drilled to 10,000 feet would be on the order of $1,800,000, or about $175 per foot.

Based on all this, EPA’s assumed injection well costs, on average, are within the range associated with recent well drilling costs.

However, it is important to note that the 2006 API drilling cost survey shows that drilling costs, on average, nearly doubled between 2003 and 2006, and that

trend has continued after 2006. Moreove r, if demand for drilling wells

associated with GS increases dramatica lly, causing competition for drilling rigs between oil and gas exploration and produc tion and GS, drilling costs are likely to rise even more, perhaps substantially. This should be at least noted, if not accounted for, in EPA’s cost assessment.

Injection well cost assumptions in the EPA costs analysis appear not to reflect all of the additional requirements on well construction that the proposed regulations may require, in partic ular, the potential costs of .

As described above, while EPA’s drilling cost assumptions appear consistent with current well drilling and completion costs, the proposed regulations may require

substantial enhancements to standard dr illing requirements. For example, the proposed rule states:

"Due to the buoyancy of CO2, today’s propos al includes enhancements to typical deep well construction procedures to provi de additional barriers to CO2 leakage outside of the injection zone. The proposal would require that surface casing for GS wells be set through the base of the lowermost USDW and cemented to the surface. The long-string casing would be cemented in place along its entire length. GS wells would also be constructed with a packer that is set opposite a cemented interval, at a locati on approved by the Director."

It is not clear that the costs of all of these additional requirements were

considered in EPA’s cost assessment.

Moreover, the proposed rule recognizes that under some circumstances, fracturing of the injection zone may be necessary to allow sufficient injectivity of CO2 (provided a specified set of conditions are met). This will be particularly true for very deep and low permeability aquifers. No consideration of such fracturing costs is apparent in EPA’s cost analyses.

138EPA appears not to consider the costs of surface equipment associated with CO2 injection operations

In addition to the Injection wells, add itional surface equipment can often be associated with CO2 injection operati ons. These costs include CO2 storage vessels, high pressure pumps and vaporiz ers, distribution/pr oduction headers, and CO2 distribution lines when multiple injection wells are needed. It is not apparent that all of these costs are in cluded in the EPA costs estimates. This

would result in an underestimate of on the order of $60,000 - $70,000 per well. In addition, many sites would require additional compression, and perhaps, substantially more extensiv e piping infrastructure; costs also not apparently considered in EPA’s analyses. If this is the case, the cost underestimate could be substantially greater.

Individual Response: With regard to injection well cost s, EPA acknowledges that the proposal cost analysis underestimated the necessary surf ace casing lengths, which must be long enough to be set through the base of th e lowermost USDW (to meet the requirements of the final GS regulation). The Cost Analysis for the final GS Rule assumes that surface casing will run from

the wellhead to the base of the lowermost USDW.

EPA acknowledges that hydraulic fracturing is a practice that may be employed at some GS project sites. However, it is a practice that is not required, entails additional permitting, and can only be undertaken with Directo r’s approval. Because of these factors, EPA believes it is a practice that will be minimally employed and did not include it in the cost analysis.

EPA did consider the cost of surface equipment associated with CO2 injection. The unit cost estimate for wellhead and control equipment used in the cost analyses for both the proposed and

final rules is based on a 2008 Petroleum Services Association of Canada (PSAC) Well Cost Study and accounts for the maximum tons injected per well per day. For costing purposes, EPA adopts the conservative assumption that all project sites will need compressors/pumps. This costs $20,700 per injection well and $1,550 per pump horsepower.

For additional information on the final costing ap proach, please see the final cost analysis and technology and cost document in the final rule docket.

Letter ID: 0170 Comment ID: 29285 Letter Lines: 2740 to 2788

Comment Code: 6100 3.1 Comments on the cost estimates

Comment: EPA assumptions that the cost analyses be based on the assumption that there will be no new climate change regulations appears inconsistent with the rationale for the proposed GS rule.

EPA’s cost analyses are based on an antic ipated level of GS activity in the United States under the existing regulatory conditions, as per EPA guidelines on

139economic analysis. In this baseline anal ysis, EPA assumes that there will be no new national climate change regulations. Based on this assumption, EPA assumed there will be only 22 projects that would be affected by the proposed GS rule. These projects include 12 anticipated DOE pilot projects, 3 projects proposed by DOE under the restructured FutureGen program, and 7 anticipated projects to be developed under state and regi onal incentive prog rams.[FN8]

[FN8: Environmental Protection Agency, "C ost Analysis for the Proposed Federal Requirements Under the Underground Injec tion Control Program for Carbon Dioxide Geologic Sequestration Wells (Proposed GS Ru le)" Office of Wate r (4606-M) July 2008 (pp. 3-4 to 3-5)]

EPA does recognize that alternative assump tions about the future deployment of projects could dramatically change the potential costs of the proposed rule, [FN9] and performed a sensitivity analysis on this assuming a 50% increase in the number of projects.

[FN9: Ibid, p 5-33]

Nonetheless, this appears to be somewhat inconsistent with th e primary rationale for the rule. In the introductory disc ussion in the proposed GS rule, EPA describes the important role that GS can play in helping to mitigate global greenhouse gas emissions, and states that:

"CCS technologies could potentially repr esent a significant pe rcentage of the cumulative effort for reducing CO2 emissions worldwide."

Moreover, the draft of the propos ed GS rule goes on to say:

"Establishing a supporting regulatory framew ork for the future development and deployment of CCS technology can provide the regulatory certainty needed to foster industry adoption of CCS, which is crucial to supporting the goals of any proposed climate change legislation."

However, despite this rationale, the EPA co st analyses basically assume that no new GS projects other than those alre ady proposed would result from the implementation of the proposed rule.

If this is in fact the case, it inevitab ly leads to the question: Why issue the proposed rule in the first place? All of the proposed projects assumed in the baseline are in the process of be ing pursued under existing regulatory authorities; and are not nece ssarily dependent on the promulgation of a new GS rule to be pursued.

Individual Response: EPA clarifies that addressing climate change is outside the scope of the GS rulemaking. Rather, the purpose of the GS regulat ion is to ensure that GS is conducted in a

140141 manner that protects USDWs from endangerment.

Because EPA cannot predict the future deployment of projects not yet in the planning stages, EPA developed the GS Rule project baseline usi ng a survey conducted with regional partners in 2010 from DOE and additional projects from indus try knowledge and publicly available data. Using a costing baseline that is based on current legislation onl y, and that does not take into account predictions of future legi slation, is also consistent w ith OMB guidance Circular A-4 on how to conduct economic analysis in support of rulemaking. However, EPA realizes the inherent uncertainty in the assumptions of baseline depl oyment, and did conduct a supplemental analysis

that considered an alternative le gislative scenario. The results of this supplemental analysis are provided in the Cost Analysis document (Chapter 5).

EPA notes that the baseline number of projects used in the proposal cost analysis is based on the assumption that if any project could possibly get approved under current regulations, that permit would most closely resemble a Class I Non-Hazardous well. In both the proposal and final rule cost analysis, the baseline scenario used for costing was then considered to be Class I nonhazardous regulations, and the changes in ri sk and costs incurred under each regulatory alternative were compared to that baseline to determine the relative risks and incremental costs

of the GS Rule.

For additional information on the final costing ap proach, please see the final cost analysis and technology and cost document in the final rule docket.